10-Q/A 1 l02706ae10vqza.txt FIRSTENERGY CORP., ET AL 10-Q/AMENDMENT NO. 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q/A AMENDMENT NO. 1 (MARK ONE) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO ----------------- -------------------
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO. ----------- ----------------------------- ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (AN OHIO CORPORATION) 76 SOUTH MAIN STREET AKRON, OH 44308 TELEPHONE (800)736-3402 1-2578 OHIO EDISON COMPANY 34-0437786 (AN OHIO CORPORATION) 76 SOUTH MAIN STREET AKRON, OH 44308 TELEPHONE (800)736-3402 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020 (AN OHIO CORPORATION) C/O FIRSTENERGY CORP. 76 SOUTH MAIN STREET AKRON, OH 44308 TELEPHONE (800)736-3402 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (AN OHIO CORPORATION) C/O FIRSTENERGY CORP. 76 SOUTH MAIN STREET AKRON, OH 44308 TELEPHONE (800)736-3402 TELEPHONE (800)736-3402
Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Indicate by check mark whether each registrant is an accelerated filer ( as defined in Rule 12b-2 of the Act): Yes X No ----- ----- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
OUTSTANDING CLASS AS OF MAY 9, 2003 ----- ----------------- FirstEnergy Corp., $.10 par value 297,636,276 Ohio Edison Company, no par value 100 The Cleveland Electric Illuminating Company, no par value 79,590,689 The Toledo Edison Company, $5 par value 39,133,887
FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. This combined Form 10-Q/A is separately filed by FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy. This Form 10-Q/A includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, further investigation into the causes of the August 14, 2003, power outage, and other similar factors. EXPLANATORY NOTE This Amendment No. 1 for FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company is being filed to restate certain amounts in the consolidated financial statements for three months ended March 31, 2002 and 2003. As described in Note 1 to the consolidated financial statements of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company, the Registrants have restated their financial statements to reflect a change in the method of amortizing the costs associated with the Ohio transition plan and recognition of above-market values of certain leased generation facilities These restatements have resulted in a decrease in net income of $22.5 million, $0.1 million, $5.0 million and $4.5 million reported for FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company, respectively, for the three months ended March 31, 2003. Net income as reported for the three months ended March 31, 2002 increased $1.8 million, $10.3 million $2.2 million and $1.0 million for FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company, respectively. TABLE OF CONTENTS
PAGES PART I. FINANCIAL INFORMATION Notes to Financial Statements....................................... 1-21 FIRSTENERGY CORP. Consolidated Statements of Income................................... 22 Consolidated Balance Sheets......................................... 23-24 Consolidated Statements of Cash Flows............................... 25 Report of Independent Auditors...................................... 26 Management's Discussion and Analysis of Results of Operations and Financial Condition............................................... 27-47 OHIO EDISON COMPANY Consolidated Statements of Income................................... 48 Consolidated Balance Sheets......................................... 49-50 Consolidated Statements of Cash Flows............................... 51 Report of Independent Auditors...................................... 52 Management's Discussion and Analysis of Results of Operations and Financial Condition............................................... 53-60 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Consolidated Statements of Income................................... 61 Consolidated Balance Sheets......................................... 62-63 Consolidated Statements of Cash Flows............................... 64 Report of Independent Auditors...................................... 65 Management's Discussion and Analysis of Results of Operations and Financial Condition............................................... 66-73 THE TOLEDO EDISON COMPANY Consolidated Statements of Income................................... 74 Consolidated Balance Sheets......................................... 75-76 Consolidated Statements of Cash Flows............................... 77 Report of Independent Auditors...................................... 78 Management's Discussion and Analysis of Results of Operations and Financial Condition............................................... 79-87 CONTROLS AND PROCEDURES................................................ 88 PART II. OTHER INFORMATION
PART I. FINANCIAL INFORMATION FIRSTENERGY CORP. AND SUBSIDIARIES OHIO EDISON COMPANY AND SUBSIDIARIES THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES THE TOLEDO EDISON COMPANY AND SUBSIDIARY NOTES TO FINANCIAL STATEMENTS (UNAUDITED) 1 - FINANCIAL STATEMENTS: The principal business of FirstEnergy Corp. (FirstEnergy) is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), Pennsylvania Power Company (Penn), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). These utility subsidiaries are referred to throughout as "Companies." Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) with GPU, Inc., the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group, Inc. (MYR); MARBEL Energy Corporation; FirstEnergy Nuclear Operating Company (FENOC); GPU Capital, Inc.; GPU Power, Inc.; FirstEnergy Service Company (FECO); and GPU Service, Inc. (GPUS). FES provides energy-related products and services and, through its FirstEnergy Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation business. FENOC operates the Companies' nuclear generating facilities. FSG is the parent company of several heating, ventilating, air conditioning and energy management companies, and MYR is a utility infrastructure construction service company. MARBEL is a fully integrated natural gas company. GPU Capital owns and operates electric distribution systems in foreign countries (see Note 3) and GPU Power owns and operates generation facilities in foreign countries. FECO and GPUS provide legal, financial and other corporate support services to affiliated FirstEnergy companies. Significant intercompany transactions have been eliminated. The Companies follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The condensed unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K and Amendments Nos. 1 and 2 on Forms 10-K/A for the year ended December 31, 2002 for FirstEnergy and the Companies. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from those estimates. The reported results of operations are not indicative of results of operations for any future period. Certain prior year amounts have been reclassified to conform with the current year presentation, as discussed further in Note 5. Preferred Securities The sole assets of the CEI subsidiary trust that is the obligor on the preferred securities included in FirstEnergy's and CEI's Capitalizations are $103.1 million aggregate principal amount of 9% junior subordinated debentures of CEI due December 31, 2006. CEI has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. Met-Ed and Penelec each formed statutory business trusts for the issuance of $100 million each of preferred securities due 2039 and included in FirstEnergy's, Met-Ed's and Penelec's respective Capitalizations. Ownership of the respective Met-Ed and Penelec trusts is through separate wholly-owned limited partnerships, of which a wholly-owned subsidiary of each company is the sole general partner. In these transactions, the sole assets and sources of revenues of each trust are the preferred securities of the applicable limited partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103.1 million each) of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. 1 Securitized Transition Bonds In June 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. JCP&L does not own or did not purchase any of the transition bonds, which are included in long-term debt on FirstEnergy's and JCP&L'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. JCP&L, 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. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from transition bond charge collections. Derivative Accounting FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt will be included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from derivative contracts are included in other operating expenses. The current net deferred loss of $105.8 million included in Accumulated Other Comprehensive Loss (AOCL) as of March 31, 2003, for derivative hedging activity, as compared to the December 31, 2002 balance of $110.2 million in net deferred losses, resulted from a $8.8 million reduction related to current hedging activity and a $4.4 million increase due to net hedge gains included in earnings during the three months ended March 31, 2003. Approximately $20.2 million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. However, the fair value of these derivative instruments will fluctuate from period to period based on various market factors and will generally be more than offset by the margin on related sales and revenues. FirstEnergy also entered into fixed-to-floating interest rate swap agreements during 2002 to increase the variable-rate component of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues-protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations resulting in no ineffectiveness in these hedge positions. The swap agreements consummated in the first quarter of 2003 are based on a notional principal amount of $200 million. As of March 31, 2003, the notional amount of FirstEnergy's fixed-for-floating rate interest rate swaps totaled $700 million. FirstEnergy engages in the trading of commodity derivatives and periodically experiences net open positions. FirstEnergy's risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. Comprehensive Income Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. As of March 31, 2003, FirstEnergy's AOCL was approximately $657.4 million as compared to the December 31, 2002 balance of $656.1 million. Comprehensive income for the first quarter of 2003 and 2002 are shown in the following table: 2
THREE MONTHS ENDED MARCH 31, ----------------------------- 2003 2002 ------------ ------------ RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------ ------------ (IN THOUSANDS) Net income ............................ $ 218,502 $ 118,268 Other comprehensive income, net of tax: Derivative hedge transactions ....... 4,341 35,844 All other ........................... 1,484 730 ------------ ------------ Comprehensive income .................. $ 224,327 $ 154,842 ============ ============
Stock-Based Compensation FirstEnergy applies the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, 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 effects of applying fair value accounting to FirstEnergy's stock options would be to reduce net income and earnings per share. The following table summarizes this effect.
THREE MONTHS ENDED MARCH 31, --------------------------- 2003 2002 ----------- ----------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) (IN THOUSANDS) Net Income, as reported ........................ $ 218,502 $ 118,268 Add back compensation expense reported in net income, net of tax (based on APB 25) ............................ 43 43 Deduct compensation expense based upon fair value, net of tax .................. (2,983) (1,402) ----------- ----------- Adjusted net income ............................ $ 215,562 $ 116,909 ----------- ----------- Earnings Per Share of Common Stock - Basic As Reported ................................ $ 0.74 $ 0.40 Adjusted ................................... $ 0.73 $ 0.40 Diluted As Reported ................................ $ 0.74 $ 0.40 Adjusted ................................... $ 0.73 $ 0.40
Change in Previously Reported Income Statement Classification - FirstEnergy recorded an increase to income during the three months ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million) relative to a decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified in operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the three months ended March 31, 2002 are reflected in the restatements shown below. 3 RESTATEMENTS OF PREVIOUSLY REPORTED RESULTS FirstEnergy, OE, CEI and TE have restated their financial statements for the year ended December 31, 2002 and for the three months ended March 31, 2003 and 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial adjustments recorded in the first quarter of 2003 that related to prior periods are now reported in results for the earlier periods. The net impact of these adjustments increases net income by $6.2 million in the first quarter of 2003. Included in the adjustments are the impact in the first quarter ended March 31, 2002 of recognizing a reserve on the deferred costs incurred subsequent to the merger associated with this Company's rate matter in Pennsylvania (see note 4). The impact of this restatement increased net income in the first quarter ended March 31, 2002 by $12 million. See Note 2(M) of the FirstEnergy, OE, CEI, and TE Form 10-K/A for further discussion of the restatements. Transition Cost Amortization As discussed in Regulatory Matters in Note 4, FirstEnergy, OE, CEI and TE amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition plan through the end of 2009. The following table summarizes the previously reported transition cost amortization and the restated amounts under the revised method for the three months ended March 31, 2002 and 2003:
Three Months Ended Three Months Ended March 31, 2002 March 31, 2003 ------------------------------- ------------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- -------- ------------- -------- OE $ 76,176 $ 68,176 $ 98,927 $101,927 CEI 13,141 37,141 16,802 41,602 TE 7,892 24,292 13,023 28,423 -------- -------- -------- -------- Total FirstEnergy $ 97,209 $129,609 $128,752 $171,952 ======== ======== ======== ========
Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant was recorded as a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $722 million (CEI $ 611 million, TE $111 million) associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of Statement of Financial Accounting Standard (SFAS) No. 142 (SFAS 142). The total above market lease obligation of $755 million (CEI $457 million, TE $298 million) associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization schedules for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI and 2007 for TE. 4 The effects of these changes and the change as described under "Change in Previously Reported Income Statement Classification" on the Consolidated Statements of Income previously reported for the three months ended March 31, 2003 and 2002 are as follows: FIRSTENERGY
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)) Revenues $ 3,244,472 $3,233,756 $ 2,853,278 $2,853,278 Expenses 2,800,758 2,824,465 2,363,634 2,362,342 ------------- ---------- ------------- ---------- Income before interest and income taxes 443,714 409,291 489,644 490,936 Net interest charges 202,740 206,040 278,722 278,722 Income taxes 102,136 93,773 94,429 93,946 ------------- ---------- ------------- ---------- Income before discontinued operations and cumulative effect of accounting change 138,838 109,478 116,493 118,268 Discontinued operations -- 6,877 Cumulative effect of accounting change 102,147 102,147 -- -- ------------- ---------- ------------- ---------- Net income $ 240,985 $ 218,502 $ 116,493 $ 118,268 ============= ========== ============= ========== Basic earnings per share of common stock $ 0.82 $ 0.74 $ 0.40 $ 0.40 Diluted earnings per share of common stock $ 0.82 $ 0.74 $ 0.40 $ 0.40
OE
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS) Revenues $ 742,743 $ 742,743 $ 707,799 $ 707,799 Expenses 673,054 672,661 610,735 600,449 ------------- ---------- ------------- ---------- Operating income 69,689 70,082 97,064 107,350 Other income 14,031 13,501 512 512 ------------- ---------- ------------- ---------- Income before net interest charges 83,720 83,583 97,576 107,862 Net interest charges 26,498 26,498 41,225 41,225 ------------- ---------- ------------- ---------- Income before cumulative effect of accounting change 57,222 57,085 56,351 66,637 Cumulative effect of accounting change 31,720 31,720 -- -- ------------- ---------- ------------- ---------- Net income 88,942 88,805 56,351 66,637 Preferred stock dividend requirements 659 659 2,596 2,596 ------------- ---------- ------------- ---------- Earnings on common stock $ 88,283 $ 88,146 $ 53,755 $ 64,041 ============= ========== ============= ==========
CEI
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS) Revenues $ 419,771 $ 419,771 $ 424,977 $ 433,277 Expenses 363,467 365,760 369,655 375,752 ------------- ---------- ------------- ---------- Operating income 56,304 54,011 55,322 57,525 Other income 4,741 4,741 5,241 5,241 ------------- ---------- ------------- ---------- Income before net interest charges 61,045 58,752 60,563 62,766 Net interest charges 40,754 43,454 47,867 47,867 ------------- ---------- ------------- ---------- Income before cumulative effect of accounting change 20,291 15,298 12,696 14,899 Cumulative effect of accounting change 42,378 42,378 -- -- ------------- ---------- ------------- ---------- Net income 62,669 57,676 12,696 14,899 Preferred stock dividend requirements (759) (759) 8,256 6,556 ------------- ---------- ------------- ---------- Earnings(loss) attributable to common stock $ 63,428 $ 58,435 $ 4,440 $ 8,343 ============= ========== ============= ==========
5 TE
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) Revenues $ 231,822 $ 231,822 $ 244,167 $ 252,567 Expenses 221,195 226,345 234,509 241,879 ------------- ---------- ------------- ---------- Operating income 10,627 5,477 9,658 10,688 Other income 3,100 3,100 4,343 4,343 ------------- ---------- ------------- ---------- Income before net interest charges 13,727 8,577 14,001 15,031 Net interest charges 10,677 9,977 14,709 14,709 ------------- ---------- ------------- ---------- Income (loss) before cumulative effect of accounting change 3,050 (1,400) (708) 322 Cumulative effect of accounting change 25,550 25,550 -- -- ------------- ---------- ------------- ---------- Net income (loss) 28,600 24,150 (708) 322 Preferred stock dividend requirements 1,605 2,205 4,724 4,724 ------------- ---------- ------------- ---------- Earnings(loss) attributable to common stock $ 26,995 $ 21,945 $ (5,432) $ (4,402) ============= ========== ============= ==========
The effects of these changes on the Consolidated Statements of Cash Flows previously reported for the three months ended March 31, 2003 and 2002, are as follows: FE
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 240,985 $ 218,502 $ 116,493 $ 118,268 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 281,662 324,862 262,828 309,374 Nuclear fuel and lease amortization 14,918 14,918 20,965 20,965 Other amortization (4,613) (4,613) (3,537) (3,537) Deferred costs recoverable as regulatory assets (38,748) (38,748) (70,134) (90,934) Deferred income taxes 40,619 31,352 (20,534) (21,017) Investment tax credits (6,259) (6,259) (6,746) (6,746) Cumulative effect of accounting change (Note 5) (174,663) (174,663) -- -- Receivables 1,602 (1,898) 60,095 60,095 Materials and supplies 11,413 11,413 18,163 18,163 Accounts payable (18,915) (7,115) (3,004) (3,004) Accrued taxes 98,896 97,553 82,297 82,297 Accrued interest 89,599 89,599 86,579 86,579 Deferred rents & sale/leaseback 3,558 (17,592) 71,438 44,400 Prepayments & other (69,673) (69,673) 109,551 109,551 Other (8,119) (5,376) (260,370) (260,370) ------------- ---------- ------------- ---------- Net cash provided from operating activities $ 462,262 $ 462,262 $ 464,084 $ 464,084 ------------- ---------- ------------- ----------
6 OE
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 88,942 $ 88,805 $ 56,351 $ 66,637 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 105,385 108,385 92,130 75,730 Nuclear fuel and lease amortization 7,106 7,106 11,402 11,402 Deferred income taxes 8,683 7,683 (13,170) (7,380) Investment tax credits (3,580) (3,704) (3,773) (3,449) Cumulative effect of accounting change (54,109) (54,109) -- -- Receivables (26,409) (29,909) 64,148 64,148 Materials and supplies (1,298) (1,298) (1,642) (1,642) Accounts payable 14,470 14,470 (18,295) (18,295) Accrued taxes 4,478 6,051 56,884 56,884 Accrued interest 2,437 2,437 6,237 6,237 Deferred rents & sale/leaseback 31,683 31,683 31,683 31,683 Prepayments & other (14,893) (14,893) 16,095 16,095 Other (9,378) (9,190) (30,539) (30,539) ------------- ---------- ------------- ---------- Net cash provided from operating activities $ 153,517 $ 153,517 $ 267,511 $ 267,511 ------------- ---------- ------------- ----------
CEI
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 62,669 $ 57,676 $ 12,696 $ 14,899 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 26,557 51,357 28,471 52,471 Nuclear fuel and lease amortization 5,044 5,044 5,990 5,990 Other amortization (4,613) (4,613) (3,892) (3,892) Deferred income taxes 35,474 33,804 7,196 822 Investment tax credits (965) (1,202) (902) (1,043) Receivables 15,242 15,242 6,816 (1,484) Materials and supplies (128) (128) (1,366) (1,366) Accounts payable (44,129) (44,129) 18,322 18,322 Cumulative effect of accounting change (72,547) (72,547) -- -- Other (17,784) (35,684) 14,191 2,803 ------------- ---------- ------------- ---------- Net cash provided from operating activities $ 4,820 $ 4,820 $ 87,522 $ 87,522 ------------- ---------- ------------- ---------
7 TE
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2003 MARCH 31, 2002 --------------------------- --------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 28,600 $ 24,150 $ (708) $ 322 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 20,240 35,640 21,368 37,768 Nuclear fuel and lease amortization 2,768 2,768 3,573 3,573 Deferred income taxes 22,675 19,130 5,314 1,242 Investment tax credits (498) (514) (486) (526) Receivables 12,249 12,249 20,022 11,622 Materials and supplies (727) (727) (651) (651) Accounts payable (53,917) (53,917) 2,861 1,161 Cumulative effect of accounting change (43,751) (43,751) -- -- Other (17,590) (24,979) 14,472 11,254 ------------- ---------- ------------- ---------- Net cash provided from (used for) operating activities $ (29,951) $ (29,951) $ 65,765 $ 65,765 ------------- ---------- ------------- ----------
2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $3.1 billion (OE-$268 million, CEI-$312 million, TE-$169 million, Penn-$123 million, JCP&L-$462 million, Met-Ed-$288 million, Penelec-$328 million, ATSI-$131 million, FES-$823 million and other subsidiaries-$147 million) for property additions and improvements from 2003-2007, of which approximately $727 million (OE-$86 million, CEI-$96 million, TE-$54 million, Penn-$53 million, JCP&L-$102 million, Met-Ed-$53 million, Penelec-$54 million, ATSI-$25 million, FES-$124 million and other subsidiaries-$80 million) is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $485 million (OE-$55 million, CEI-$53 million, TE-$34 million, Penn-$42 million and FES-$301 million), of which approximately $69 million (OE-$23 million, CEI-$15 million, TE-$12 million and Penn-$19 million) applies to 2003. Guarantees and Other Assurances As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of March 31, 2003, outstanding guarantees and other assurances aggregated $960.2 million. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood that such parental guarantees of $872.7 million as of March 31, 2003 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $25.8 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions. Various energy supply contracts contain credit enhancement provisions in the form of cash collateral or letters of credit in the event of a reduction in credit rating below investment grade. These provisions vary and typically require more than one rating reduction to fall below investment grade by Standard & Poor's or Moody's Investors Service to trigger additional collateralization by FirstEnergy. As of March 31, 2003, rating-contingent collateralization totaled $61.7 million. FirstEnergy monitors these collateralization provisions and updates its total exposure monthly. 8 Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio for which hearings began in February 2003. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable 9 societal benefits charge. The Companies have total accrued liabilities aggregating approximately $53.9 million (JCP&L-$47.1 million, CEI-$2.5 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.3 million and other-$3.6 million) as of March 31, 2003. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations but is unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. Other Commitments and Contingencies GPU made significant investments in foreign businesses and facilities through its GPU Capital and GPU Power subsidiaries. Although FirstEnergy attempts to mitigate its risks related to foreign investments, it faces additional risks inherent in operating in such locations, including foreign currency fluctuations. EI Barranquilla, a wholly owned subsidiary of GPU Power, is a 28.67% equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which owns a Colombian independent power generation project. GPU Power is committed through September 30, 2003, under certain circumstances, to make additional standby equity contributions to TEBSA of $21.3 million, which FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA project is $239 million as of March 31, 2003. The lenders include the Overseas Private Investment Corporation, US Export Import Bank and a commercial bank syndicate. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $5.9 million (subject to escalation) under the project's operations and maintenance agreement. FirstEnergy provided the TEBSA project lenders a $50 million letter of credit (LOC) issued by Bank One under FirstEnergy's existing $250 million LOC capacity available as part of the $1.5 billion FirstEnergy credit facility to obtain TEBSA lender consent to abandon its Argentina operations, GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) (see Note 3 below). Legal Matters Various lawsuits, claims and proceedings related to the FirstEnergy's normal business operations are pending against it and its subsidiaries. The most significant applicable to the Company are described above. 3 - DIVESTITURES: INTERNATIONAL OPERATIONS- FirstEnergy had identified certain former GPU international operations for divestiture within one year of the merger. These operations constitute individual "lines of business" as defined in APB Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force ( EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's 2001 Consolidated Statement of Income. Additionally, assets and liabilities of these international operations had been segregated under separate captions on the Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon in the quarter ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the 10 purchase price and reversal of the effects of EITF Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the quarter ended March 31, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications. See Note 1 for the effects of the change in classification. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge to reduce the carrying value of its remaining 20.1 percent interest. GPU's former Argentina operations were also identified by FirstEnergy for divestiture within one year of the merger. FirstEnergy determined the fair value of Emdersa, based on the best available information as of the date of the merger. Subsequent to that date, a number of economic events have occurred in Argentina which may have an impact on FirstEnergy's ability to realize Emdersa's estimated fair value. These events included currency devaluation, restrictions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. FirstEnergy did not reach a definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these assets were no longer classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2002. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). In October 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy also recognized a currency translation adjustment (CTA) in other comprehensive income (OCI) of $91.5 million as of December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This adjustment represents the impact of translating Emdersa's financial statements from its functional currency to the U.S. dollar for GAAP financial reporting. On April 18, 2003, FirstEnergy divested its ownership in Emdersa. The abandonment was accomplished by relinquishing FirstEnergy's shares of Emdersa's parent company, GPU Argentina Holdings, to that company's independent Board of Directors, relieving FirstEnergy of all rights and obligations relative to this business. As a result of this action, FirstEnergy's gains and losses related to discontinuing these operations have been presented as a separate item on the Consolidated Statements of Income - "Discontinued operations" - in accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Due to the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million in the second quarter of 2003. This charge resulted from realizing $89.8 million of currency translation losses through current period earnings, partially offset by a $22.4 million gain recognized from eliminating FirstEnergy's investment in Emdersa. Discontinued operations for the six-month period reflected a net after-tax charge of $60.5 million, which included $6.9 million of earnings from Emdersa in the first quarter of 2003. As a result of the abandonment, FirstEnergy has substantially divested all of GPU Capital's international operations. The $67.4 million charge does not include the anticipated income tax benefits related to the abandonment. These tax benefits will be fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. SALE OF GENERATING ASSETS- In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy for damages, based on the anticipatory breach of the agreement. On February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's request for arbitration against NRG. In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approximately $74 million ($43 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 4 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the Companies' respective state regulatory plans: - allowing the Companies' electric customers to select their generation suppliers; 11 - establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; - allowing recovery of potentially stranded investment (sometimes referred to as transition costs); - itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the Companies' electric generation businesses; and - continuing regulation of the Companies' transmission and distribution systems. Ohio In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs (see note 1) and $0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Ohio Companies were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the respective transition cost recovery period. If the customer shopping goals established in the agreement had not been achieved by the end of 2005, the transition cost recovery periods could have been shortened for OE, CEI and TE to reduce recovery by as much as $500 million (OE - $250 million, CEI - $170 million and TE - $80 million). The Ohio Companies achieved all of their required 20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that there will be no regulatory action reducing the recoverable transition costs. New Jersey JCP&L's 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which remain in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable societal benefits charge (SBC) to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge (MTC) 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 JCP&L's request for an Internal Revenue Service (IRS) ruling regarding the treatment of associated federal income tax benefits is 12 acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy's or JCP&L's net income since the contingency existed prior to the merger. In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. In 2002, JCP&L received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs and which 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 the transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet. JCP&L's PLR obligation to provide basic generation service (BGS) to non-shopping customers is supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of March 31, 2003, the accumulated deferred cost balance totaled approximately $530 million. The NJBPU also allowed securitization of JCP&L's deferred balance to the extent permitted by law upon application by JCP&L 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 were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the NJBPU in August 2002. 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 MTC and SBC 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. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances approximating $17 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings requesting an aggregate rate increase of approximately $122 million in base electric rates and the recovery of deferred costs based on the securitization methodology discussed above. If the securitization methodology is not allowed, then JCP&L has requested deferred cost recovery over a four-year period with a return on the unamortized deferred cost balance. This alternative would increase the overall rate request to approximately $246 million. JCP&L strongly disagrees with many of the positions taken by NJBPU Staff. The Staff's position would result in a $119 million estimated annual earnings decrease related to the electricity delivery charge. In addition, the Staff recommended disallowing approximately $153 million of deferred energy costs which would result in a one-time pre-tax charge against earnings of $153 million (or $0.31 per share of common stock). JCP&L will respond to the Staff's position in its Reply Brief which is due on May 21, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. 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 JCP&L'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 an hourly price bid (applicable to all large industrial customers) process. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances. Pennsylvania The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's 13 situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger. As a result of their generating asset divestitures, Met-Ed and Penelec obtained their supply of electricity to meet their PLR obligations almost entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec filed a petition with the PPUC seeking permission to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding. In June 2001, the PPUC entered orders approving the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the merger and provided Met-Ed and Penelec PLR deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and Penelec to defer for future recovery the difference between their actual energy costs and those reflected in their capped generation rates, retroactive to January 1, 2001. Correspondingly, in the event that energy costs incurred by Met-Ed and Penelec would be below their respective capped generation rates, that difference would have reduced costs that had been deferred for recovery in future periods. This PLR deferral accounting procedure was denied in a court decision discussed below. Met-Ed's and Penelec's PLR obligations extend through December 31, 2010; during that period competitive transition charge (CTC) revenues would have been applied to their stranded costs. Met-Ed and Penelec would have been permitted to recover any remaining stranded costs through a continuation of the CTC after December 31, 2010 through no later than December 31, 2015. Any amounts not expected to be recovered by December 31, 2015 would have been written off at the time such nonrecovery became probable. Several parties had filed Petitions for Review in June and July 2001 with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders. On February 21, 2002, the Court affirmed the PPUC decision regarding the FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to the issue of merger savings. The Court reversed the PPUC's decision regarding the PLR obligations of Met-Ed and Penelec, and rejected those parts of the settlement that permitted the companies to defer for accounting purposes the difference between their wholesale power costs and the amount that they collect from retail customers. FirstEnergy and the PPUC each filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002, asking it to review the Commonwealth Court decision. Also on March 25, 2002, Citizens Power filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme Court. In September 2002, FirstEnergy established reserves for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million. The reserves reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. FirstEnergy recorded an aggregate non-cash charge to income of $55.8 million ($32.6 million net of tax), or $0.11 per share of common stock, for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003. Because FirstEnergy had already reserved for the deferred energy costs and FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and Penelec believe that the disallowance of continued CTC recovery of PLR costs will not have a future adverse financial impact during that period. Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale currently runs through December 2003 and will be automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at or below the shopping credit for their uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and amounts recovered through their capped generation rates. 5 - NEW ACCOUNTING STANDARDS: In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with 14 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 (ARO) 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. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003 asset retirement costs were recorded in the amount of $602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.109 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. At December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.243 billion. FirstEnergy expects substantially all nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn would be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for these operating companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $174.7 million increase to income, or a $102.1 million increase net of tax, or $0.35 per share of common stock (basic and diluted). FirstEnergy recorded an ARO for nuclear decommissioning ($1.096 billion) of the Beaver Valley 1, Beaver Valley 2, Davis-Besse, Perry, and TMI-2 nuclear generation facilities with the remaining ARO related to Bruce Mansfield's sludge impoundment facilities and two coal ash disposal sites. The Company maintains nuclear decommissioning trust funds, which had balances at March 31, 2003 of $1.061 billion. This number represents the fair value of the assets that are legally restricted for purposes of settling the nuclear decommissioning ARO. The following table provides the beginning and ending aggregate carrying amount of the ARO and the changes to the balance for the period of January 1, 2003 through March 31, 2003.
ARO RECONCILIATION ------------------ (MILLIONS) Beginning balance as of January 1, 2003 ........................ $1,109 Liabilities incurred in the current period.................... -- Liabilities settled in the current period..................... -- Accretion expense............................................. 18 Revisions in estimated cash flows............................... -- ------ ENDING BALANCE AS OF MARCH 31, 2003............................. $1,127 ------
The following table provides on an adjusted basis the year-end balance of the ARO related to nuclear decommissioning and sludge impoundment for 2002, as if SFAS 143 had been adopted on January 1, 2002.
ADJUSTED ARO RECONCILIATION --------------------------- (MILLIONS) Beginning balance as of January 1, 2002......................... $1,042 Accretion 2002.................................................. 67 ------ ENDING BALANCE AS OF DECEMBER 31, 2002 ........................ $1,109 ------
In accordance with SFAS 143 FirstEnergy ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates that are applied to the generation assets. This practice recognizes accumulated depreciation in excess of the historical cost of an asset, because the removal cost exceeds the estimated salvage value. The change in accounting resulted in a $60 million credit to income as part of the SFAS 143 cumulative effect adjustment. Beginning in 2003 depreciation rates applied to non-regulated generation assets will exclude the cost of removal component and cost of removal will be charged to income rather than charged to the accumulated provision for depreciation. In accordance with SFAS 71, the regulated plant assets will continue the accounting practice of depreciating assets using a cost of removal component in the depreciation rates. The net removal cost credit balance included in the accumulated provision for regulated assets at March 31, 2003 is $296.1 million. The following table provides on an adjusted basis the effect on income, as if the accounting for SFAS 143 had been applied in the first quarter 2002. 15
EFFECT OF THE CHANGE IN ACCOUNTING PRINCIPLE APPLIED RETROACTIVELY TO THE FIRST QUARTER OF 2002 -------------------------------------------------- INCREASE(DECREASE) (MILLIONS) RESTATED (SEE NOTE 1) Reported net income...................... $ 118 ----- Replacement of decommissioning expense... 26 Depreciation of asset retirement cost.... (2) Accretion of asset retirement cost....... (10) Income tax effect........................ (6) ----- Total earnings effect.................... 8 ----- Net income adjusted...................... $ 126 ===== Earnings per share of common stock (basic and diluted): Net income as previously reported $0.40 Adjustment for effect of change in accounting principle applied retroactively 0.02 ----- Net income adjusted $0.42 =====
In January 2003, the FASB issued an 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 after June 15, 2003 (FirstEnergy's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, 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. FirstEnergy currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. In addition to the entities FirstEnergy is currently consolidating FirstEnergy believes that the PNBV Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, which continue to be applied based on their original effective dates. FirstEnergy is currently assessing the new standard and has not yet determined the impact on its financial statements. In June 2002, the EITF reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. Prior to its adoption for 2002 year end reporting, FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation. In addition, the related KWH sales and purchases statistics described under Management's 16 Discussion and Analysis of Results of Operations and Financial Condition were reclassified. The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations.
THREE MONTHS ENDED MARCH 31, 2002 --------------------- 2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES --------------------- RESTATED RESTATED (IN MILLIONS) Total before adjustment............................. $2,893 $2,402 Adjustment.......................................... (40) (40) ------ ------ Total as reported................................... $2,853 $2,362 ====== ======
6 - SEGMENT INFORMATION: FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of interest expense related to the 2001 merger acquisition debt; the corporate support services operating segment and the international businesses acquired in the 2001 merger. The international business assets reflected in the 2002 "Other" assets amount included assets in the United Kingdom identified for divestiture (see Note 3 - Divestitures) which were sold in the second quarter of 2002. As those assets were in the process of being sold, their performance was not being reviewed by a chief operating decision maker and in accordance with SFAS 131, "Disclosures about Segments of an Enterprise and Related Information," did not qualify as an operating segment. The remaining assets and revenues for the corporate support services and the remaining international businesses were below the quantifiable threshold for operating segments for separate disclosure as "reportable segments." FirstEnergy's primary segment is its regulated services segment, which includes eight electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segment consists of the subsidiaries that operate unregulated energy and energy-related businesses. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier. The regulated services segment obtains a portion of its required generation through power supply agreements with the competitive services segment. SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING SERVICES(D) SERVICES OTHER(C) ADJUSTMENTS CONSOLIDATED(C)(D) ----------- ----------- -------- ----------- ------------------ (IN MILLIONS) THREE MONTHS ENDED: MARCH 31, 2003 External revenues ........................... $ 2,315 $ 866 $ 51 $ 12(a) $ 3,244 Internal revenues ........................... 264 560 124 (948)(b) -- Total revenues ........................... 2,579 1,426 175 (936) 3,244 Depreciation and amortization ............... 307 7 11 -- 325 Net interest charges ........................ 125 11 105 (35)(b) 206 Income taxes ................................ 167 (43) (30) -- 94 Income before cumulative effect of accounting change ................................... 216 (56) (51) -- 109 Net income .................................. 317 (55) (44) -- 218 Total assets ................................ 29,649 2,449 1,421 -- 34,287 Property additions .......................... 118 79 27 -- 224 MARCH 31, 2002 External revenues ........................... $ 1,995 $ 638 $ 214 $ 6(a) $ 2,853 Internal revenues ........................... 355 410 117 (882)(b) -- Total revenues ........................... 2,350 1,048 331 (876) 2,853 Depreciation and amortization ............... 292 7 12 -- 311 Net interest charges ........................ 161 10 122 (14)(b) 279 Income taxes ................................ 185 (41) (27) -- 117 Net income (loss) ........................... 188 (60) (22) -- 106 Total assets ................................ 29,552 2,706 6,288 (836)(b) 37,710 Property additions .......................... 144 37 14 -- 195
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting: (a) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes. (b) Elimination of intersegment transactions. (c) Amounts restated in 2002 - See Note 1. (d) Amounts restated in 2002 and 2003 - see Note 1. 17 7. SUBSEQUENT EVENTS ENVIRONMENTAL MATTERS- On August 8, 2003, FirstEnergy, OE and Penn reported a development regarding a complaint filed by the U.S. Department of Justice with respect to the W.H. Sammis Plant. As reported, on August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." Management is unable to predict the ultimate outcome of this matter. The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition. REGULATORY MATTERS- New Jersey On July 25, 2003, FirstEnergy and JCP&L announced that review is underway concerning a decision by the NJBPU on JCP&L's rate proceeding. Based on that review, JCP&L will decide its appropriate course of action, which could include filing a request for reconsideration with the NJBPU and possibly an appeal to the Appellate Division of the Superior Court of New Jersey. In its ruling, the NJBPU reduced JCP&L's annual revenues by approximately $62 million, for an average rate decrease of 3 percent, effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5 percent on JCP&L's rate base for the next 6 to 12 months. During that period, JCP&L would initiate another proceeding to request recovery of additional expenses incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction could be retroactive to August 1, 2003. The NJBPU decision reflects elimination of $111 million in annual customer credits mandated by the New Jersey Electric Discount and Energy Competition Act (EDECA); a $223 million reduction in the energy delivery charge; a net $1 million increase in the SBC; and a $49 million increase in the MTC. The $1 million net SBC increase reflects approximately a $22 million increase related to universal services' costs previously approved in a separate proceeding, as well as reductions in other components of the SBC. The MTC would allow for the recovery of $465 million of deferred energy costs over the next 10 years on an interim basis, thus disallowing $153 million of the $618 million provided for in the settlement agreement. This decision reflects the NJBPU's belief that a hindsight review comparing JCP&L's power purchases to spot market prices provides the appropriate benchmark for recovery. JCP&L's deferred energy costs primarily reflect mandated purchase power contracts with NUG's that are above wholesale market prices, and costs of providing basic generation service to customers in excess of the company's capped basic generation service charges during the transition period under EDECA, which ends August 1, 2003. At that time, the generation portion of most customer bills will increase by an average of 7.5 percent as a result of the outcome of the basic generation service auction conducted earlier this year by the BPU. In the second quarter of 2003, JCP&L recorded charges to net income aggregating $158 million ($94 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. On July 25, 2003, the NJBPU approved a Stipulation of Settlement between the parties and authorized the recovery of the total $135 million of the Freehold buyout costs, eliminating the interim nature of the recovery. Pennsylvania On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003 and for the other parties to file their responses to the Met-Ed and Penelec position paper by June 2, 2003. In summary, the Met-Ed and Penelec position paper essentially stated the following: 18 - Because no stay of the PPUC's June 2001 order approving the Settlement Stipulation was issued or sought, the Stipulation remained in effect until the Pennsylvania Supreme Court denied all appeal applications in January 2003, - As of January 16, 2003, the Supreme Court's Order became final and the portions of the PPUC's June 2001 Order that were inconsistent with the Supreme Court's findings were reversed, - The Supreme Court's finding effectively amended the Stipulation to remove the PLR cost recovery and deferral provisions and reinstated the GENCO Code of Conduct as a merger condition, and - All other provisions included in the Stipulation unrelated to these three issues remain in effect. The other parties' responses included significant disagreement with the position paper and disagreement among the other parties themselves, including the Stipulation's original signatory parties. Some parties believe that no portion of the Stipulation has survived the Commonwealth Court's Order. Because of these disagreements, Met-Ed and Penelec filed a letter on June 11, 2003 with the Administrative Law Judge assigned to the remanded case voiding the Stipulation in its entirety pursuant to the termination provisions. They believe this will significantly simplify the issues in the pending action by reinstating Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC. In addition, they have agreed to voluntarily continue certain Stipulation provisions including funding for energy and demand side response programs and to cap distribution rates at current levels through 2007. This voluntary distribution rate cap is contingent upon a finding that Met-Ed and Penelec have satisfied the "public interest" test applicable to mergers and that any rate impacts of merger savings will be dealt with in a subsequent rate case. Based upon this letter, Met-Ed and Penelec believe that the remaining issues before the Administrative Law Judge are the appropriate treatment of merger savings issues and whether their accounting and related tariff modifications are consistent with the Court Order. INTERNATIONAL OPERATIONS- Pending Sale of Remaining Investment in Avon and Sale of Note from Aquila On May 22, 2003, FirstEnergy announced it reached an agreement to sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that agreement also includes Aquila's 79.9 percent interest (See Note 3). Under terms of the agreement, Scottish and Southern will pay FirstEnergy and Aquila an aggregate $70 million (FirstEnergy's share would be approximately $14 million). Avon's debt will remain with that company. FirstEnergy also recognized in the second quarter of 2003 an impairment of $12.6 million ($8.2 million after tax) related to the carrying value of the note receivable from the initial sale of a 79.9 percent interest in Avon that occurred in May 2002. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of the note in the secondary market and received $63.2 million in proceeds on July 28, 2003. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED- SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (FirstEnergy's third quarter of 2003) for all other financial instruments. FirstEnergy did not enter into or modify any financial instruments within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy expects to classify as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $19 million as of June 30, 2003. Subsidiary preferred dividends on FirstEnergy's Consolidated Statements of Income are currently included in net interest charges. Therefore, the application of SFAS 150 will not require the reclassification of such preferred dividends to net interest charges. 19 DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. FirstEnergy is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 20 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------------ 2003 2002 ----------- ----------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ----------- ----------- (In thousands, except per share amounts) REVENUES: Electric utilities ................................................................. $ 2,315,064 $ 2,053,976 Unregulated businesses ............................................................. 918,692 799,302 ----------- ----------- Total revenues ................................................................. 3,233,756 2,853,278 ----------- ----------- EXPENSES: Fuel and purchased power ........................................................... 1,192,810 664,040 Purchased gas ...................................................................... 229,465 206,227 Other operating expenses ........................................................... 899,046 1,010,713 Provision for depreciation and amortization ........................................ 324,862 309,374 General taxes ...................................................................... 178,282 171,988 ----------- ----------- Total expenses ................................................................. 2,824,465 2,362,342 ----------- ----------- INCOME BEFORE INTEREST AND INCOME TAXES ............................................... 409,291 490,936 ----------- ----------- NET INTEREST CHARGES: Interest expense ................................................................... 200,650 260,465 Capitalized interest ............................................................... (9,152) (5,814) Subsidiaries' preferred stock dividends ............................................ 14,542 24,071 ----------- ----------- Net interest charges ........................................................... 206,040 278,722 ----------- ----------- INCOME TAXES .......................................................................... 93,773 93,946 ----------- ----------- INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE ........................................................ 109,478 118,268 Discontinued operations ............................................................... 6,877 -- Cumulative effect of accounting change (net of income taxes of $72,516,000) (Note 5) .............................................................. 102,147 -- ----------- ----------- NET INCOME ............................................................................ $ 218,502 $ 118,268 =========== =========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change ... $ 0.37 $ 0.40 Discontinued operations (net of income taxes) ...................................... 0.02 -- Cumulative effect of accounting change (net of income taxes) (Note 5) .............. 0.35 -- ----------- ----------- Net income ......................................................................... $ 0.74 $ 0.40 =========== =========== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING ................................... 293,886 292,791 =========== =========== DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change ... $ 0.37 $ 0.40 Discontinued operations (net of taxes).............................................. 0.02 -- Cumulative effect of accounting change (net of income taxes) (Note 5) .............. 0.35 -- ----------- ----------- Net income ......................................................................... $ 0.74 $ 0.40 =========== =========== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING ................................. 294,877 294,344 =========== =========== DIVIDENDS DECLARED PER SHARE OF COMMON STOCK .......................................... $ 0.375 $ 0.375 =========== ===========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 21 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ----------- ----------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ----------- ----------- (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents ................................................. $ 290,036 $ 196,301 Receivables- Customers (less accumulated provisions of $55,945,000 and $52,514,000 respectively, for uncollectible accounts) ............................. 1,149,390 1,153,486 Other (less accumulated provisions of $12,596,000 and $12,851,000, respectively, for uncollectible accounts) ............................. 439,605 469,606 Materials and supplies, at average cost- Owned ................................................................... 255,950 253,047 Under consignment ....................................................... 159,268 174,028 Other ..................................................................... 289,588 203,630 ----------- ----------- 2,583,837 2,450,098 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service ................................................................ 21,061,059 20,372,224 Less--Accumulated provision for depreciation .............................. 9,047,427 8,552,927 ----------- ----------- 12,013,632 11,819,297 Construction work in progress ............................................. 963,422 859,016 ----------- ----------- 12,977,054 12,678,313 ----------- ----------- INVESTMENTS: Capital trust investments ................................................. 1,042,143 1,079,435 Nuclear plant decommissioning trusts ...................................... 1,060,994 1,049,560 Letter of credit collateralization ........................................ 277,763 277,763 Other ..................................................................... 899,551 918,874 ----------- ----------- 3,280,451 3,325,632 ----------- ----------- DEFERRED CHARGES: Regulatory assets ......................................................... 8,336,176 8,753,401 Goodwill .................................................................. 6,237,274 6,278,072 Other ..................................................................... 872,625 900,837 ----------- ----------- 15,446,075 15,932,310 ----------- ----------- $34,287,417 $34,386,353 =========== ===========
22 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ------------ ------------ RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------ ------------ (IN THOUSANDS) CAPITALIZATION AND LIABILITIES CURRENT LIABILITIES: Currently payable long-term debt and preferred stock ............... $ 1,630,227 $ 1,702,822 Short-term borrowings .............................................. 855,327 1,092,817 Accounts payable ................................................... 885,651 906,468 Accrued taxes ...................................................... 550,453 455,121 Other .............................................................. 1,077,504 1,093,815 ------------ ------------ 4,999,162 5,251,043 ------------ ------------ CAPITALIZATION: Common stockholders' equity- Common stock, $.10 par value, authorized 375,000,000 shares - 297,636,276 shares outstanding ................................. 29,764 29,764 Other paid-in capital ............................................ 6,119,286 6,120,341 Accumulated other comprehensive loss ............................. (657,411) (656,148) Retained earnings ................................................ 1,743,324 1,634,981 Unallocated employee stock ownership plan common stock - 3,613,860 and 3,966,269 shares, respectively ................... (71,662) (78,277) ------------ ------------ Total common stockholders' equity ............................ 7,163,301 7,050,661 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption .............................. 335,123 335,123 Subject to mandatory redemption .................................. 18,519 18,521 Subsidiary-obligated mandatorily redeemable preferred securities ... 409,971 409,867 Long-term debt ..................................................... 11,038,490 10,872,216 ------------ ------------ 18,965,404 18,686,388 ------------ ------------ DEFERRED CREDITS: Accumulated deferred income taxes .................................. 2,099,427 2,069,682 Accumulated deferred investment tax credits ........................ 230,472 236,184 Asset retirement obligation ........................................ 1,126,786 -- Nuclear plant decommissioning costs ................................ -- 1,243,558 Power purchase contract loss liability ............................. 3,015,816 3,136,538 Retirement benefits ................................................ 1,643,501 1,564,930 Lease market valuation liability ................................... 1,084,850 1,106,000 Other .............................................................. 1,121,999 1,092,030 ------------ ------------ 10,322,851 10,448,922 ------------ ------------ COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2) .................... ------------ ------------ $ 34,287,417 $ 34,386,353 ============ ============
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets. 23 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED MARCH 31, -------------------------- 2003 2002 --------- --------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) --------- --------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income ...................................................................... $ 218,502 $ 118,268 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization ................................ 324,862 309,374 Nuclear fuel and lease amortization ........................................ 14,918 20,965 Other amortization, net .................................................... (4,613) (3,537) Deferred costs recoverable as regulatory assets ............................ (38,748) (90,934) Deferred income taxes, net ................................................. 31,352 (21,017) Investment tax credits, net ................................................ (6,259) (6,746) Cumulative effect of accounting change (Note 5) ............................ (174,663) -- Receivables ................................................................ (1,898) 60,095 Materials and supplies ..................................................... 11,413 18,163 Accounts payable ........................................................... (7,115) (3,004) Accrued taxes .............................................................. 97,553 82,297 Accrued interest ........................................................... 89,599 86,579 Deferred rents and sale/leaseback .......................................... (17,592) 44,400 Prepayments & other ........................................................ (69,673) 109,551 Other ...................................................................... (5,376) (260,370) --------- --------- Net cash provided from operating activities .............................. 462,262 464,084 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt ............................................................. 297,696 105,031 Short-term borrowings, net ................................................. -- 115,556 Redemptions and Repayments- Preferred stock ............................................................ -- (185,299) Long-term debt ............................................................. (200,866) (183,905) Short-term borrowings, net ................................................. (237,490) -- Common stock dividend payments ............................................... (110,159) (109,726) --------- --------- Net cash provided from (used for) financing activities ................... (250,819) (258,343) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions ........................................................... (224,419) (195,292) Avon cash and cash equivalents previously held for sale (Note 3) ............. -- 411,822 Net assets held for sale ..................................................... -- (61,565) Proceeds from nonutility generation trusts ................................... 106,327 34,208 Proceeds from assets sale .................................................... 60,572 -- Cash investments ............................................................. 24,715 (4,343) Other ........................................................................ (84,903) 36,968 --------- --------- Net cash provided from (used for) investing activities ................... (117,708) 221,798 --------- --------- Net increase in cash and cash equivalents ....................................... 93,735 427,539 Cash and cash equivalents at beginning of period ................................ 196,301 220,178 --------- --------- Cash and cash equivalents at end of period ...................................... $ 290,036 $ 647,717 ========= =========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 24 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of FirstEnergy Corp.: We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the quarters ended March 31, 2003 and 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for goodwill in 2002 as discussed in Note 2(E) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements for the year ended December 31, 2002 as discussed in Note 2(L) and Note 2(M) to those consolidated financial statements) dated February 28, 2003, except as to Note 2(L), which is as of May 9, 2003, and Note 2(M), which is as of August 18, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003, except as to Note 1, which is as of August 18, 2003 25 FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FirstEnergy Corp. is a registered public utility holding company that provides regulated and competitive energy services (see Results of Operations - Business Segments) domestically and internationally. The international operations were acquired as part of FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU Capital, Inc. and its subsidiaries provide electric distribution services in foreign countries. GPU Power, Inc. and its subsidiaries develop, own and operate generation facilities in foreign countries. Sales are planned but not pending for the remaining international operations (see Capital Resources and Liquidity). Regulated electric distribution services are provided in Ohio by wholly owned subsidiaries (Ohio electric utilities) - Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), and The Toledo Edison Company (TE). Regulated services are provided in Pennsylvania through wholly owned subsidiaries (Pennsylvania electric utilities) - Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec) and Pennsylvania Power Company (Penn) - a wholly owned subsidiary of OE. Jersey Central Power & Light Company (JCP&L) provides electric distribution services in New Jersey. Transmission services are provided in the franchise areas of the Ohio electric utilities and Penn by wholly owned subsidiary American Transmission Systems, Inc. (ATSI). Transmission services are provided by Met-Ed, Penelec and JCP&L in their respective franchise areas. The coordinated delivery of energy and energy-related products, including electricity, natural gas and energy management services, to customers in competitive markets is provided through a number of subsidiaries. Subsidiaries providing competitive services include FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG), MARBEL Energy Corporation and MYR Group, Inc. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy is restating its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003 and 2002. The restatements reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2006 for OE, 2007 for TE and in 2009 for CEI. FirstEnergy and the Ohio utilities amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, versus the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. The amortization expense under the revised method (see Note 1) increased by $32.4 million and $43.2 million for the three months ended March 31, 2002 and 2003, respectively. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant was recorded as 26 a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $722 million (CEI $611 million, TE $111 million) associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS No. 142. The total above market lease obligation of $755 million (CEI $457 million, TE $298 million) associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization schedules for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI and 2007 for TE. RESULTS OF OPERATIONS Net income in the first quarter of 2003 was $218.5 million or $0.74 per share of common stock (basic and diluted), compared to $118.3 million or $0.40 per share of common stock (basic and diluted) in the first quarter of 2002. Results in the first quarter of 2003 included an after tax charge of $6.9 or $0.02 per share of common stock (basic and diluted) resulting from the abandonment of Emdersa's parent company, GPU Argentina Holdings, Inc on April 18, 2003. Results in the first quarter of 2003 included an after-tax charge of $6.9 million or $0.02 per share of common stock (basic and diluted) resulting from the abandonment of Emdersa's Parent Company, GPU Argentina Holdings, Inc. on April 18, 2003. Net income in the first quarter of 2003 included an after-tax credit of $102.1 million resulting from the cumulative effect of an accounting change due to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Income before discontinued operations and the cumulative effect of an accounting change was $109.5 million in the first three months of 2003, or $0.37 per share of common stock (basic and diluted). Results in the first quarter of 2003, benefited from increased revenues due to cold weather, increased gas margins, and reduced financing costs. Partially offsetting these favorable factors were higher employee benefit expenses and incremental costs (which reduced basic and diluted earnings per share by $0.18) related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration). Reclassifications of Previously Reported Income Statement FirstEnergy recorded an increase to income during the three months ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million) relative to its decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified in operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the three months ended March 31, 2002 are shown in Note 1. In June 2002, the Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Therefore, revenues and expenses for the first quarter of 2002 have been reclassified (see Implementation of Recent Accounting Standard). Revenues Total revenues increased $380.5 million in the first quarter of 2003, compared to the same period last year as a result of additional sales in FirstEnergy's regulated and competitive service segments. Electric and gas sales revenue increased due to colder than normal weather in the first quarter of 2003 compared to milder than normal weather in the first three months of 2002. Sources of changes in revenues during the first quarter of 2003 compared to the first quarter of 2002 are summarized in the following table: 27
SOURCES OF REVENUE CHANGES -------------------------- INCREASE (DECREASE) (IN MILLIONS) Electric Utilities (Regulated Services): Retail electric sales .......................... $ 108.2 Wholesale electric sales ....................... 139.5 All other revenues ............................. 13.4 -------- Total Electric Utilities ......................... 261.1 -------- Unregulated Businesses (Competitive Services): Retail electric sales .......................... 66.7 Wholesale electric sales ....................... 233.8 Gas sales ...................................... 43.9 FSG ............................................ (42.4) Other .......................................... (8.9) -------- Total Unregulated Businesses ..................... 293.1 -------- International .................................... (173.1) Other ............................................ (0.6) -------- Net Revenue Increase ............................. $ 380.5 ========
Electric Sales Retail sales by FirstEnergy's electric utility operating companies (EUOC) increased by $108.2 million in the first quarter of 2003 compared to the first quarter of 2002. Temperatures in the EUOC service areas ranged from 20% to 30% colder in the first quarter of 2003, compared to the same period last year, increasing residential and commercial heating loads. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the same quarter of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES ------------------------------ INCREASE (DECREASE) Electric Generation Sales: Retail Regulated services ............ 2.1% Competitive services .......... 130.2% Wholesale ..................... 141.3% ----- Total Electric Generation Sales ... 30.6% ===== EUOC Distribution Deliveries: Residential ..................... 15.4% Commercial ...................... 11.7% Industrial ...................... 1.3% ----- Total Distribution Deliveries ..... 9.4% =====
Shopping by customers for alternative energy suppliers and the effect of a sluggish national economy in FirstEnergy's service areas combined to reduce regulated retail generation sales revenue by $4.7 million in the first quarter of 2003 from the same period in 2002, despite the colder weather in 2003. Sales of electric generation by alternative suppliers in Ohio, Pennsylvania and New Jersey in the first quarter of 2003 increased by 8.8, 4.4 and 0.8 percentage points, respectively, or 5.8 percentage points on a consolidated basis from the first quarter of 2002. Revenues from distribution deliveries increased by $127.2 million or 11.2% in the first quarter of 2003 compared to the first quarter of 2002 largely due to the colder temperatures. Increased kilowatt-hour deliveries resulted from additional demand from all three customer segments: residential, commercial and industrial. The slower industrial growth continued to reflect sluggish economic conditions. Partially offsetting the increase in revenues from distribution deliveries were Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $14.4 million of additional credits in the first quarter of 2003 compared to the same period in 2002. These reductions in revenue are deferred for future recovery under the Ohio transition plan and do not materially affect current period earnings. EUOC sales to wholesale customers increased by $139.5 million in the first quarter of 2003 from the same quarter last year. The increase occurred almost entirely at JCP&L and resulted from the auction of its entire basic 28 generation service (BGS) responsibility to alternative suppliers. At the direction of the New Jersey Board of Public Utilities (NJBPU), JCP&L is selling its pre-existing sources of power supply, including energy provided by non-utility generation (NUG) contracts, into the wholesale market. Electric generation sales by FirstEnergy's competitive segment increased $300.5 million in the first quarter of 2003 from the first quarter of 2002, primarily from additional sales to the wholesale market ($233.8 million) as FES began supplying a portion of New Jersey's BGS requirements in September 2002. Retail sales by FirstEnergy's competitive services segment increased by $66.7 million from kilowatt-hour sales that were more than double the prior year's level. That increase resulted in part from retail customers switching to FES, under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio were partially offset by lower retail sales in markets outside of Ohio. FirstEnergy's regulated and unregulated subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three months ended March 31, 2003 and 2002 are summarized as follows:
THREE MONTHS ENDED MARCH 31, -------------------- 2003 2002 ---- ---- (IN MILLIONS) Sales.............. $336 $46 Purchases.......... 361 80 ---- ----
FirstEnergy'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 it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell to the wholesale market. International revenues declined $162.3 million due to the sale of a 79.9% interest in Avon during the second quarter of 2002 and the subsequent application of equity accounting to FirstEnergy's remaining 20.1% interest. As a result, no revenues were recorded for FirstEnergy's equity interest in Avon in the first quarter of 2003. Nonelectric Sales Nonelectric sales revenues of the competitive services segment declined by $7.4 million in the first quarter of 2003 from the same period in 2002. Reduced revenues from FSG were substantially offset by higher natural gas sales revenues resulting from a weather-stimulated increase in prices in the first three months of 2003. The reduced revenues from FSG also reflected the sales in early 2003 of Colonial Mechanical and Webb Technologies, as well as continued declines associated with weak economic conditions. Expenses Total expenses increased $462.1 million in the first quarter of 2003 from the same quarter of 2002. Sources of changes in expenses in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table:
AS PREVIOUSLY AS REPORTED RESTATED -------- -------- SOURCES OF EXPENSE CHANGES -------------------------- INCREASE (DECREASE) (IN MILLIONS) Fuel and purchased power ............. $ 497.3 $ 528.8 Purchased gas ........................ 23.2 23.2 Other operating expenses ............. (108.5) (111.7) Depreciation and amortization ........ 18.8 15.5 General taxes ........................ 6.3 6.3 -------- -------- Net Expense Increase ................... $ 437.1 462.1 ======== ========
The net increase in expenses in the first quarter of 2003 compared to the first quarter of 2002 was primarily due to a $528.8 million increase in purchased power costs. The increase resulted from additional volumes to cover supply obligations assumed by FES for sales to the New Jersey market to provide BGS, and additional supplies required to replace Davis-Besse power during its extended outage (see Davis-Besse Restoration). The extended outage at the Davis-Besse nuclear plant produced a decline in nuclear generation of 16.7% in the first quarter of 2003, compared to the first quarter of 2002. Purchased gas costs increased by $23.2 million in the first quarter of 2003 compared to the 29 same period of 2002 due to higher unit costs, partially offset by lower volumes purchased to meet reduced sales levels. Despite reduced quantities of gas sold, gross profit margins improved by $18.5 million during the first quarter of 2003, compared to the same period last year. Other operating expenses decreased $111.7 million in the first quarter of 2003 from the first quarter of 2002. The decrease primarily resulted from reduced business volume from domestic energy-related businesses which lowered other operating expenses by $66.1 million, reduced international expenses of $72.5 million (due to the sale of Avon) and the absence of one-time charges recorded in the first quarter of 2002 of $78.2 million. The reduced volume of energy-related business reflected the sale in early 2003 of the Colonial Mechanical and Webb Technologies businesses, as well as continued declines associated with weak economic conditions. Partially offsetting these lower expenses were $36.3 million of additional nuclear costs resulting from the Davis-Besse extended outage, $50.4 million in higher employee benefit costs and the absence of a $38.5 million credit cumulative restatement adjustment (see Restatements). Charges for depreciation and amortization increased by $15.5 million in the first quarter of 2003 compared to the first quarter of 2002. The higher charges primarily resulted from three factors - increased amortization of the Ohio transition regulatory assets ($17.1 million), recognition of depreciation on four fossil plants ($9.6 million) which had been held pending sale in the first quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002, reduced tax related deferrals in 2003 ($7.9 million) and a $2.1 million increase in the amortization of the above-market lease costs regulatory assets discussed above. Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals in Ohio ($14.4 million) and lower charges resulting from the implementation of SFAS 143 ($11.6 million), including revised service life assumptions for generating plants ($8.0 million). Net Interest Charges Net interest charges decreased $72.7 million in the first quarter of 2003 compared to the same period of 2002. FirstEnergy's redemption and refinancing of its outstanding debt and preferred stock over the last twelve months, resulted in a $57.1 million reduction of financing costs. In addition, the sale of FirstEnergy's 79.9% interest in Avon eliminated $18.9 million of financing costs. Redemption and refinancing activities during the first quarter of 2003 totaled $122 million (excluding net reductions to various revolving bank facilities) and $563 million, respectively, and are expected to result in annualized savings of approximately $20 million. Partially offsetting these savings were $2.4 million of incremental interest costs associated with the issuance of $250 million of new senior notes. FirstEnergy also exchanged existing fixed-rate payments on outstanding debt (principal amount of $700 million as of March 31, 2003) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $6.9 million in the first quarter of 2003, compared to the first quarter of 2002 as a result of these swaps. Discontinued Operations In April 2003, FirstEnergy divested its ownership in GPU Emperssa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) through the abandonment of its shares in the parent company of the Argentina operation. FirstEngery has reclassified the results of Emdersa for the quarter ended March 31, 2003, $6.9 million of net income as discontinued operations. There was no impact in 2002 as the assets was held for sale. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 (see discussion further below) in the first quarter of 2003, FirstEnergy recorded an after-tax credit to net income of $102.1 million. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The asset retirement obligation (ARO) liability at the date of adoption was $1.109 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on decommissioning trust funds of $12 million. FirstEnergy expects substantially all of its nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $174.6 million increase to income, or $102.1 million net of income taxes. Earnings Effect of SFAS 143 In June 2001, the FASB issued SFAS 143. 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. 30 In the first quarter of 2003, application of SFAS 143 (excluding the cumulative adjustment recorded upon adoption -- See Note 5 ) resulted in the following changes to income and expense categories:
EFFECT OF SFAS 143 -- FIRST QUARTER 2003 ----------------------------------------------------------------------------- INCREASE (DECREASE) (MILLIONS) Other operating expense Cost of removal (previously included in depreciation).... $ 4.2 Depreciation Replacement of decommissioning expense................... (22.4) Depreciation of asset retirement cost.................... 1.9 Accretion of asset retirement liability.................. 9.9 Reclassification of cost of removal to expense .......... (3.9) ------ Net impact to depreciation............................... (14.5) ------ Other Income Earnings on trust balances............................... 2.5 ----- Income taxes............................................. 5.3 ----- Net income effect........................................ $7.5 =====
Postretirement Plans Sharp declines in equity markets since the second quarter of 2000 and a reduction in FirstEnergy's assumed discount rate for pensions and other postretirement obligations have combined to produce a significant increase in those costs. Also, increases in health care payments and a related increase in projected trend rates have led to higher health care costs. Combined, these employee benefit expenses increased $49.2 million in the first quarter of 2003 compared to the same period in 2002. The following table summarizes the net pension and other post-employment benefits (OPEB) expense (excluding amounts capitalized) for the three months ended March 31, 2003 and 2002.
THREE MONTHS ENDED POSTRETIREMENT EXPENSE (INCOME) MARCH 31, ------------------------------------------------------- 2003 2002 ------------------ (IN MILLIONS) Pension...................... $31.3 $(3.8) OPEB......................... 40.5 26.4 ------------------ Total...................... $71.8 $22.6 ==================
The pension and OPEB expense increases are included in various cost categories and have contributed to other cost increases discussed above. See "Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses. RESULTS OF OPERATIONS - BUSINESS SEGMENTS FirstEnergy manages its business as two separate major business segments - regulated services and competitive services. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated domestic transmission and distribution systems. It also provides generation services to franchise customers who have not chosen an alternative generation supplier. The Ohio electric utilities and Penn obtain generation through a power supply agreement with the competitive services segment (see Outlook - Business Organization). The competitive services segment also supplies a substantial portion of the "provider of last resort" (PLR) requirements for Met-Ed and Penelec under contract. The competitive services segment includes all competitive energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy services such as heating, ventilating and air-conditioning. Financial results discussed below include intersegment revenues. A reconciliation of segment financial results to consolidated financial results is provided in Note 6 to the consolidated financial statements. 31 Regulated Services Net income increased to $317 million in the first quarter of 2003, compared to $188 million in the first quarter of 2002. The factors contributing to the changes in net income are summarized in the following table:
REGULATED SERVICES -------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) Revenues .................................. $ 229.0 Expenses .................................. 242.7 -------- Income Before Interest and Income Taxes ... (13.7) Net interest charges ...................... (39.2) Income taxes .............................. (2.5) -------- Income Before Cumulative Effect of a Change in Accounting ...................... 28.0 Cumulative effect of a change in accounting 101.0 -------- Net Income ................................ $ 129.0 =======
Higher generation sales and distribution deliveries combined to increase external revenues by $247.7 million in the first quarter of 2003 compared to the same quarter of 2002. This increase was partially offset by a $31.1 million decline in revenues from lower sales to FES, resulting from the extended outage of the Davis-Besse nuclear plant, which decreased generation available for sale. The remaining change in sales resulted from an increase in energy-related revenues. The increase in expenses resulted principally from a $205.8 million increase in purchased power costs due to higher generation sales. Other operating expenses increased $14.9 million and depreciation and amortization expense was $19.9 million higher in the first quarter of 2003 compared to the same quarter last year. The increase in other operating expenses reflected additional employee benefit costs offset in part by the absence in the first quarter of 2003 of adjustments related to OE's low income housing investment and lower energy delivery costs. The increase in depreciation and amortization expense primarily resulted from three factors - increased amortization of the Ohio transition regulatory assets ($17.1 million), recognition of depreciation on four fossil plants ($9.6 million) which had been pending sale in the first quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002 and the termination of tax related deferrals in February 2003 ($7.9 million). Partially offsetting these increases in depreciation and amortization were higher incentive deferrals in Ohio ($14.4 million) and lower charges resulting from the implementation of SFAS 143 ($11.6 million), including revised service life assumptions for generating plants ($8.0 million). Competitive Services Net losses decreased to $55 million in the first quarter of 2003, compared to $59.6 million in the first quarter of 2002. The factors contributing to the reduced loss are summarized in the following table:
COMPETITIVE SERVICES ------------------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) Revenues .................................. $377.8 Expenses .................................. 351.4 ------ Income Before Interest and Income Taxes ... 26.4 ------ Net interest charges ...................... 1.0 Income taxes .............................. 10.1 ------ Income Before Cumulative Effect of a Change in Accounting .................... 15.3 Cumulative effect of a change in accounting 1.2 ------ Net Income ................................ $ 16.5 ======
The increase in revenues in the first quarter of 2003, compared to the first quarter of 2002, includes the net effect of several factors. Revenues from the electric wholesale market increased $233.8 million in the first quarter of 2003 from the same period last year as kilowatt-hour sales more than doubled resulting principally from sales as an alternative supplier for a portion of New Jersey's BGS requirements. Retail kilowatt-hour sales revenues increased $66.7 million as a result of expanding the FES business in Ohio under Ohio's electricity choice program and higher weather stimulated sales to existing customers. Natural gas sales were $43.9 million higher due to higher prices resulting from colder weather in the first quarter of 2003, compared to the same period last year. Internal sales to the regulated services segment increased $90.3 million primarily reflecting sales to Met-Ed and Penelec in supplying a substantial portion of 32 their PLR requirements in Pennsylvania. Energy-related services such as heating, ventilating and air-conditioning work reflected the divestiture in early 2003 of Colonial Mechanical and Webb Technologies, as well as continued declines associated with weak economic conditions. Revenues from energy-related services decreased $69.9 million in the first quarter of 2003 from the first quarter of 2002. Expenses increased $351.4 million in the first quarter of 2003 from the same period of 2002 primarily attributable to purchased power costs, which increased $405.8 million to source the higher kilowatt-hour sales to wholesale and retail customers. Gas costs also increased in the first quarter of 2003 by $23.2 million, reflecting higher unit costs during the colder than normal weather compared to the first quarter of 2002. Partially offsetting these factors were lower costs due to reduced business volume for domestic energy-related businesses of $61.1 million and other operating expenses which decreased $17.5 million. The decrease in other operating costs reflected the absence of $65.6 million of one-time charges in the first quarter of 2002, partially offset by higher nuclear production costs from the extended Davis-Besse outage and increased employee benefit costs (principally pension and health care). CAPITAL RESOURCES AND LIQUIDITY FirstEnergy's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy's net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, FirstEnergy expects to meet its contractual obligations with cash from operations. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.5 billion of revolving credit facilities. In the first quarter of 2003, FirstEnergy received $137.0 million of cash dividends from its subsidiaries and paid $110.2 million in cash common stock dividends to its shareholders. There are no material restrictions on the issuance of cash dividends by FirstEnergy's subsidiaries. As of March 31, 2003, FirstEnergy had $290.0 million of cash and cash equivalents, compared with $196.3 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities during the first quarter of 2003, compared with the first quarter of 2002 were as follows:
OPERATING CASH FLOWS 2003 2002 ----------------------------------------------- (IN MILLIONS) Cash earnings (1) ....... $365 $326 Working capital and other 97 138 ---- ---- Total ................... $462 $464 ==== ====
(1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $2 million due to a $41 million decrease in funds used for working capital that was offset in part by a $39 million increase in cash earnings. The change in funds used for working capital represents offsetting changes for receivables, sale and leaseback rent payments, prepayments and other. Cash Flows From Financing Activities The following table provides details regarding security issuances and redemptions during the first quarter of 2003: 33
SECURITIES ISSUED OR REDEEMED IN THE FIRST QUARTER 2003 -------------------------------------------------------------------------- (IN MILLIONS) New Issues Senior Notes .................................... 250 Long-term revolver .............................. 50 Other, primarily debt discount .................. (2) ---- 298 Redemptions First mortgage bonds ............................ 40 Pollution control notes ......................... 50 Secured notes ................................... 108 Other, primarily redemption premiums ............ 3 ---- 201 Short-term Borrowings, Net Use of Cash ............... 237 ----
Net cash flows used for financing activities declined by $8 million in the first quarter of 2003 from the first quarter of 2002. The decrease in funds used for financing activities resulted from increased financing of $77 million that exceeded $69 million of additional redemptions and repayments during the first quarter of 2003 compared to the same period of 2002. FirstEnergy had approximately $855.3 million of short-term indebtedness as of March 31, 2003 compared to $1.093 billion at the end of 2002. Available borrowing capability included $356 million under the $1.5 billion revolving lines of credit and $76 million under bilateral bank facilities. As of March 31, 2003, OE, CEI, TE and Penn had the aggregate capability to issue $2.2 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. JCP&L, Met-Ed and Penelec no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of March 31, 2003, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $443 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.5 billion of preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. On March 17, 2003, FirstEnergy filed a registration statement with the U.S. Securities and Exchange Commission covering securities in the aggregate amount of up to $2 billion. Although the Company does not have any current plans to issue securities, the shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, or share purchase contracts and related share purchase units. On April 21, 2003, OE completed a $325 million refinancing transaction that included two tranches -- $175 million of 4.00% five year notes and $150 million of 5.45% twelve year notes. The net proceeds will be used to redeem approximately $220 million of outstanding OE first mortgage bonds having a weighted average cost of 7.99%, with the remainder to be used to pay down short-term debt. On May 1 and May 2, 2003, FirstEnergy executed two fixed-for-floating interest rate swap agreements with notional values of $50 million each on underlying senior notes with an average fixed interest rate of 4.73%. Cash Flows From Investing Activities Net cash flows used for investing activities totaled $118 million in the first quarter of 2003, compared to net cash flows of $222 million provided from investing activities for the same period of 2002. The $340 million change resulted from the absence of the Avon cash amount recognized in the first quarter of 2002 resulting from the reclassification from the "Assets Pending Sale" presentation to normal operations presentation (see Note 3), increased capital expenditures and other, offset in part by an increase in cash investments and proceeds from NUG trusts. The following table summarizes first quarter of 2003 investments by FirstEnergy's regulated services and competitive services segments: 34
SUMMARY OF FIRST QUARTER 2003 PROPERTY CASH USED FOR INVESTING ACTIVITIES ADDITIONS INVESTMENTS OTHER TOTAL ------------------------------------------------------------------------------------------- SOURCES (USES) (IN MILLIONS) Regulated Services . $(118) $ 136(1) $ (8) $ 10 Competitive Services (79) 63(2) (71) (87) Other .............. (27) (77) 3 (101) Eliminations ....... -- -- 60 60 ----- ----- ----- ----- Total ......... $(224) $ 122 $ (16) $(118) ===== ===== ===== =====
(1) Includes $106 million proceeds from NUG trusts. (2) Includes $61 million proceeds from sale of assets. During the remaining three quarters of 2003, capital requirements for property additions and capital leases are expected to be approximately $578 million, including $36 million for nuclear fuel. FirstEnergy has additional requirements of approximately $378 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard & Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on its credit ratings. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." OTHER OBLIGATIONS Obligations not included on FirstEnergy's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.5 billion. Also, CEI and TE continue to sell substantially all of their retail customer receivables, which provided $145 million of financing not included in the Consolidated Balance Sheet as of March 31, 2003. GUARANTEES AND OTHER ASSURANCES As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and ratings contingent collateralization provisions. As of March 31, 2003, the maximum potential future payments under outstanding guarantees and other assurances totaled $960.2 million as summarized below: 35
MAXIMUM GUARANTEES AND OTHER ASSURANCES EXPOSURE -------------------------------------------------------- (IN MILLIONS) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1) $774.4 Financings (2)(3) .................... 98.3 ------ 872.7 Surety Bonds ........................... 25.8 Rating-Contingent Collateralization (4) 61.7 ------ Total Guarantees and Other Assurances $960.2 ======
(1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Includes parental guarantees of subsidiary debt and lease financing including FirstEnergy's letters of credit supporting subsidiary debt. (3) Issued for various terms. (4) Estimated net liability under contracts subject to rating-contingent collateralization provisions. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions. Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody's to trigger additional collateralization. EMDERSA ABANDONMENT On April 18, 2003, FirstEnergy divested its ownership of Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. Prior to the abandonment, FirstEnergy had recorded a foreign currency translation adjustment (CTA) loss of $90 million through its other comprehensive income (OCI) - a component of common stockholders' equity. The CTA reduced FirstEnergy's common stockholders' equity and did not affect its net income. As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash charge of $63 million, or $0.21 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through its current period earnings ($90 million, or $0.30 per share), partially offset by the gain recognized from eliminating its investment in Emdersa ($27 million, or $0.09 per share). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $63 million charge will be an increase in common stockholders' equity of $27 million. The $63 million charge does not include the anticipated income tax benefits related to the abandonment, which will be fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. When realized, the $129 million of tax benefits will represent positive cash flows for FirstEnergy and increase its common stockholders' equity by $50 million. MARKET RISK INFORMATION FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. 36 Commodity Price Risk FirstEnergy is exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of FirstEnergy's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2003 is summarized in the following table:
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, 2003 ............... $ 53.8 $ 24.1 $ 77.9 New contract value when entered ........................... -- -- -- Additions/Increase in value of existing contracts ......... 17.2 29.1 46.3 Change in techniques/assumptions .......................... -- -- -- Settled contracts ......................................... (4.6) (10.3) (14.9) ------ ------ ------ Outstanding net asset as of March 31, 2003 (1) ............ 66.4 42.9 109.3 ------ ------ ------ NON-COMMODITY NET ASSETS AS OF MARCH 31, 2003: Interest Rate Swaps (2) ................................... -- 24.0 24.0 ------ ------ ------ Net Assets - Derivatives Contracts as of March 31, 2003 (3) $ 66.4 $ 66.9 $133.3 ====== ====== ====== Impact of Changes in Commodity Derivative Contracts (4) Income Statement Effects (Pre-Tax) ........................ $ (3.5) $ -- $ (3.5) Balance Sheet Effects: Other Comprehensive Income (Pre-Tax) ...................... $ -- $ 18.8 $ 18.8 Regulatory Liability ...................................... $ 16.1 $ -- $ 16.1
(1) Includes $50.3 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or discount. (3) Excludes $26.7 million of derivative contract fair value decrease, as of March 31, 2003, representing FirstEnergy's 50% share of Great Lakes Energy Partners, LLC. (4) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
NON-HEDGE HEDGE TOTAL (IN MILLIONS) ------------------------------------------------------------------------ CURRENT- Other Assets ......... $ 30.1 $ 31.1 $ 61.2 Other Liabilities .... (32.4) (2.3) (34.7) NON-CURRENT- Other Deferred Charges 70.4 38.9 109.3 Other Deferred Credits (1.7) (0.8) (2.5) ------ ------ ------ Net assets ........... $ 66.4 $ 66.9 $133.3 ====== ====== ======
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, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses 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: 37
SOURCE OF INFORMATION - FAIR VALUE BY CONTRACT YEAR 2003(1) 2004 2005 2006 THEREAFTER TOTAL ------------------------------------------------------------------------------------------------------- (IN MILLIONS) Prices actively quoted(2) $ 12.6 $ 2.6 $ -- $ -- $ -- $ 15.2 Other external sources(3) 26.7 15.8 9.3 -- -- 51.8 Prices based on models .. -- -- -- 6.3 36.0 42.3 ------ ------ ------ ------ ------ ------ TOTAL(4) ............. $ 39.3 $ 18.4 $ 9.3 $ 6.3 $ 36.0 $109.3 ====== ====== ====== ====== ====== ======
(1) For the last three quarters of 2003. (2) Exchange traded. (3) Broker quote sheets. (4) Includes $50.3 million from an embedded option that is offset by a regulatory liability and does not affect earnings. FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2003. Based on derivative contracts held as of March 31, 2003, an adverse 10% change in commodity prices would decrease net income by approximately $4.7 million for the next twelve months. Interest Rate Swap Agreements During the first quarter of 2003, FirstEnergy entered into fixed-to-floating interest rate swap agreements, as part of its ongoing efforts to manage the interest rate risk of its liability portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, fixed interest rates and interest payment dates match those of the underlying obligations. The swap agreements consummated in the first quarter of 2003 are based on a notional principal amount of $200 million. Throughout the second half of 2002 and the first quarter of 2003, FirstEnergy utilized fixed-to-floating interest rate swap agreements to increase the variable-rate component of its debt portfolio. As of March 31, 2003, the debt underlying FirstEnergy's $700 million notional amount of outstanding fixed-for-floating interest rate swaps had a weighted average fixed interest rate of 7.10%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.09%. GPU Power (through a subsidiary) used existing dollar-denominated interest rate swap agreements in the first quarter of 2003. The GPU Power agreements convert variable-rate debt to fixed-rate debt to manage the risk of increases in variable interest rates. GPU Power's swaps had a weighted average fixed interest rate of 6.68% as of March 31, 2003 and December 31, 2002. The following summarizes the principal characteristics of the swap agreements: Interest Rate Swaps
MARCH 31, 2003 DECEMBER 31, 2002 ---------------------------- --------------------------------- NOTIONAL MATURITY FAIR NOTIONAL MATURITY FAIR DENOMINATION AMOUNT DATE VALUE AMOUNT DATE VALUE ------------------------------------------------------------------ (DOLLARS IN MILLIONS) Fixed to Floating Rate (Fair value hedges) $ 200 2006 $ 2.4 350 2023 14.5 $ 444 2023 $ 15.5 150 2025 7.9 150 2025 5.9 Floating to Fixed Rate (Cash flow hedges) . $ 13 2005 $ (0.8) $ 16 2005 $ (0.9) ------- ------- ------- ------- ------- -------
Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $528 million and $532 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $53 million reduction in fair value as of March 31, 2003. OUTLOOK FirstEnergy continues to pursue its goal of being the leading regional supplier of energy and related services in the northeastern quadrant of the United States, where it sees the best opportunities for growth. Its fundamental business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional 38 presence, key elements for its strategy are in place and management's focus continues to be on execution. FirstEnergy intends to provide competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to its core business. As FirstEnergy's industry changes to a more competitive environment, FirstEnergy has taken and expects to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. FirstEnergy's current focus includes: 1) returning Davis-Besse to safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio; 3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's cost structure; and 5) enhancing its credit profile and financial flexibility. Business Organization FirstEnergy's business is managed as two distinct operating segments - a competitive services segment and a regulated services segment. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. FirstEnergy expects the transfer of ownership of EUOC non-nuclear generating assets to FGCO will be substantially completed by the end of the market development period in 2005. All of the EUOC power supply requirements for the Ohio Companies and Penn are provided by FES to satisfy their PLR obligations, as well as grandfathered wholesale contracts. State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the EUOC's respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of the EUOCs varies. Those provisions include: - allowing the EUOC's electric customers to select their generation suppliers; - establishing PLR obligations to non-shopping customers in the EUOC's service areas; - allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; - itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the EUOC's electric generation businesses; and - continuing regulation of the EUOC's transmission and distribution systems. Regulatory assets are costs that the respective 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 the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. Regulatory assets declined $417.2 million to $8.3 billion as of March 31, 2003 from the balance as of December 31, 2002, with approximately one-half of the decrease related to the adoption of SFAS 143 by JCP&L, Met-Ed, Penelec and Penn. The regulatory assets of the individual companies are as follows:
REGULATORY ASSETS AS OF MARCH 31, DECEMBER 31, COMPANY 2003 2002 --------------------------------------------------------------- RESTATED (SEE NOTE 1) (IN MILLIONS) OE .... $1,765.2 $1,848.7 CEI ... 1,170.4 1,191.8 TE .... 557.4 578.2 Penn .. 77.8 156.9 JCP&L . 3,094.8 3199.0 Met-Ed 1,126.9 1,179.1 Penelec 543.7 599.7 -------- -------- Total . $8,336.2 $8,753.4 ======== ========
39 Ohio FirstEnergy's transition plan (which FirstEnergy filed on behalf of its Ohio electric utilities) included approval for recovery of transition costs, including regulatory assets, as filed in the transition plan through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The approved plan also granted preferred access over FirstEnergy's subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. In February 2003, the Ohio electric utilities were authorized increases in revenues aggregating approximately $50 million (OE - $41 million, CEI - $4 million and TE - $5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the respective transition cost recovery periods. New Jersey 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. JCP&L submitted two rate filings with the New Jersey Board of Public Utilities (NJBPU) in August 2002. 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 (SBC) rates; one proposed method of recovery of these costs is the securitization of the deferred balance. Hearings began in February 2003. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances approximating $17 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings requesting an aggregate rate increase of approximately $122 million in base electric rates and the recovery of deferred costs based on the securitization methodology discussed above. If the securitization methodology is not allowed, then JCP&L has requested deferred cost recovery over a four-year period with a return on the unamortized deferred cost balance. This alternative would increase the overall rate request to approximately $246 million. JCP&L strongly disagrees with many of the positions taken by NJBPU Staff. The Staff's position would result in a $119 million estimated annual earnings decrease related to the electricity delivery charge. In addition, the Staff recommended disallowing approximately $153 million of deferred energy costs which would result in a one-time pre-tax charge against earnings of $153 million (or $0.31 per share of common stock). JCP&L will respond to the Staff's position in its Reply Brief which is due on May 21, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. 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 JCP&L's BGS obligation of 5,100 megawatts 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. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsets to its deferred energy cost balances. Pennsylvania Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at or below the shopping credit for their uncommitted PLR energy costs during the term of the agreement to FES. FES has hedged most of Met-Ed's and Penelec's unfilled on-peak 40 PLR obligation through 2004 and a portion of 2005. Met-Ed and Penelec will continue to defer those cost differences between NUG contract rates and the rates reflected in their capped generation rates. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's decision which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003. Because FirstEnergy had already reserved for the deferred energy costs and FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005, FirstEnergy, Met-Ed and Penelec believe that the disallowance of competitive transition charge recovery of PLR costs above Met-Ed's and Penelec's capped generation rates will not have a future adverse financial impact during that period. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Total incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. It is anticipated that an additional $13.7 million in maintenance costs will be expended over the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse through the summer of 2003 and has completed some hedging for the balance of 2003 as well based on a probabilistic assessment of the unit's expected start-up date. Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO(2)) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO(2) regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO(2) and nitrogen oxides (NO(x)) reduction requirements under the Clean Air Act Amendments of 1990. SO(2) reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO(x) reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO(x) reductions from the Companies' Ohio and Pennsylvania facilities. The 41 EPA's NO(x) Transport Rule imposes uniform reductions of NO(x) emissions (an approximate 85% reduction in utility plant NO(x) emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NO(x) emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NO(x) budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NO(x) budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NO(x) budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The civil complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. Several EUOC have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through the SBC. The Companies have total accrued liabilities aggregating approximately $53.9 million as of March 31, 2003. The effects of compliance on the EUOC with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. 42 Legal Matters It is FirstEnergy's understanding that, as of August 18, 2003, five individual shareholder-plaintiffs have filed separate complaints against FirstEnergy alleging various securities law violations in connection with the restatement of earnings described herein. Most of these complaints have not yet been officially served on the Company. Moreover, FirstEnergy is still reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is, however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against it, the most significant of which are described herein. Power Outage On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. Having restored service to its customers, FirstEnergy is now in the process of accumulating data and evaluating the status of its electrical system prior to and during the outage event and would expect that the same effort Is under way at utilities and regional transmission operators across the region. As of August 18, 2003, the following facts about FirstEnergy's system were known. Early in the afternoon of August 14, hours before the event, Unit 5 of the Eastlake Plant in Eastlake, Ohio tripped off. Later in the afternoon, three FirstEnergy transmission lines and one owned by American Electric Power and FirstEnergy tripped out of service. The Midwest Independent System Operator (MISO), which oversees the regional transmission grid, indicated that there were a number of other transmission line trips in the region outside of FirstEnergy's system. FirstEnergy customers experienced no service interruptions resulting from these conditions. Indications to FirstEnergy were that the Company's system was stable. Therefore, no isolation of FirstEnergy's system was called for. In addition, FirstEnergy determined that its computerized system for monitoring and controlling its transmission and generation system was operating, but the alarm screen function was not. However, MISO's monitoring system was operating properly. FirstEnergy believes that extensive data needs to be gathered and analyzed in order to determine with any degree of certainty the circumstances that led to the outage. This is a very complex situation, far broader than the power line outages FirstEnergy experienced on its system. From the preliminary data that has been gathered, FirstEnergy believes that the transmission grid in the Eastern Interconnection, not just within FirstEnergy's system, was experiencing unusual electrical conditions at various times prior to the event. These included unusual voltage and frequency fluctuations and load swings on the grid. FirstEnergy is committed to working with the North American Electric Reliability Council and others involved to determine exactly what events in the entire affected region led to the outage. There is no timetable as to when this entire process will be completed. It is, however, expected to last several weeks, at a minimum. IMPLEMENTATION OF RECENT ACCOUNTING STANDARD In June 2002, the EITF reached a partial consensus on Issue No. 02-03. Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation (see Note 5). In addition, the related kilowatt-hour sales and purchases statistics described above under Results of Operations were reclassified (1.3 billion kilowatt-hour in the first quarter of 2002). The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations.
IMPACT OF RECORDING ENERGY TRADING NET ON THE PREVIOUSLY REPORTED FIRST QUARTER OF 2002 REVENUES EXPENSES ------------------------------------------------------------------------------ (IN MILLIONS) Total before adjustment $ 2,893 $ 2,402 Adjustment ............ (40) (40) ------- ------- Total as reported ..... $ 2,853 $ 2,362 ======= =======
SIGNIFICANT ACCOUNTING POLICIES FirstEnergy prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of FirstEnergy's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed 43 below are similarly reviewed with their risks and uncertainties reflecting these specific factors. FirstEnergy's more significant accounting policies are described below. Purchase Accounting - Acquisition of GPU Purchase accounting 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 for GPU were based primarily on estimates. The more significant of these included the estimation of the fair value of the international operations, certain domestic operations and the fair value of the pension and other post-retirement benefit assets and liabilities. The purchase price allocations for the GPU acquisition were finalized in the fourth quarter of 2002. Regulatory Accounting FirstEnergy's regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine FirstEnergy is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which FirstEnergy operates, a significant amount of regulatory assets have been recorded - $8.3 billion as of March 31, 2003. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. 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. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows 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: - Net energy generated or purchased for retail load - Losses of energy over transmission and distribution lines - Mix of kilowatt-hour usage by residential, commercial and industrial customers - Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be 44 affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the end of 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in the first quarter of 2002 were computed assuming a 10.25% rate of return on plan assets. Beginning in the first quarter of 2003, the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In developing FirstEnergy's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, FirstEnergy recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its 45 carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur FirstEnergy would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill -- fair value was higher than carrying value for each of its reporting units. The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. As of March 31, 2003, FirstEnergy had $6.2 billion of goodwill that primarily relates to its regulated services segment. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (FirstEnergy's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, 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. FirstEnergy currently consolidates the majority of these entities and believe it will continue to consolidate following the adoption of FIN 46. In addition to the entities FirstEnergy is currently consolidating FirstEnergy believes that the PNBV Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, which continue to be applied based on their original effective dates. FirstEnergy is currently assessing the new standard and has not yet determined the impact on its financial statements. 46 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------------- 2003 2002 ------------ ------------ RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------ ------------ (IN THOUSANDS) OPERATING REVENUES ................................................................. $ 742,743 $ 707,799 --------- --------- OPERATING EXPENSES AND TAXES: Fuel ............................................................................ 12,850 14,290 Purchased power ................................................................. 243,828 241,479 Nuclear operating costs ......................................................... 125,368 95,234 Other operating costs ........................................................... 90,273 79,611 --------- --------- Total operation and maintenance expenses ...................................... 472,319 430,614 Provision for depreciation and amortization ..................................... 108,385 75,730 General taxes ................................................................... 48,256 45,376 Income taxes .................................................................... 43,701 48,729 --------- --------- Total operating expenses and taxes ............................................ 672,661 600,449 --------- --------- OPERATING INCOME ................................................................... 70,082 107,350 OTHER INCOME ....................................................................... 13,501 512 --------- --------- INCOME BEFORE NET INTEREST CHARGES ................................................. 83,583 107,862 --------- --------- NET INTEREST CHARGES: Interest on long-term debt ...................................................... 24,488 33,073 Allowance for borrowed funds used during construction and capitalized interest .. (1,380) (621) Other interest expense .......................................................... 2,478 5,147 Subsidiaries' preferred stock dividend requirements ............................. 912 3,626 --------- --------- Net interest charges .......................................................... 26,498 41,225 --------- --------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ............................... 57,085 66,637 Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 5) 31,720 -- --------- --------- NET INCOME ......................................................................... 88,805 66,637 PREFERRED STOCK DIVIDEND REQUIREMENTS .............................................. 659 2,596 --------- --------- EARNINGS ON COMMON STOCK ........................................................... $ 88,146 $ 64,041 ========= =========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. 47 OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ---------- ---------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ---------- ---------- (IN THOUSANDS) ASSETS UTILITY PLANT: In service ......................................................... $5,139,199 $4,989,056 Less--Accumulated provision for depreciation ....................... 2,573,462 2,552,007 ---------- ---------- 2,565,737 2,437,049 ---------- ---------- Construction work in progress- Electric plant ................................................... 145,785 122,741 Nuclear fuel ..................................................... 47,974 23,481 ---------- ---------- 193,759 146,222 ---------- ---------- 2,759,496 2,583,271 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: PNBV Capital Trust ................................................. 401,972 402,565 Letter of credit collateralization ................................. 277,763 277,763 Nuclear plant decommissioning trusts ............................... 296,298 293,190 Long-term notes receivable from associated companies ............... 503,510 503,827 Other .............................................................. 70,708 74,220 ---------- ---------- 1,550,251 1,551,565 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents .......................................... 14,320 20,512 Receivables- Customers (less accumulated provisions of $5,708,000 and $5,240,000, respectively for uncollectible accounts) ........... 296,218 296,548 Associated companies ............................................. 619,084 592,218 Other (less accumulated provisions of $1,000,000 for uncollectible accounts at both dates) ........................................ 33,430 30,057 Notes receivable from associated companies ......................... 264,736 437,669 Materials and supplies, at average cost- Owned ............................................................ 58,564 58,022 Under consignment ................................................ 20,509 19,753 Prepayments and other .............................................. 26,697 11,804 ---------- ---------- 1,333,558 1,466,583 ---------- ---------- DEFERRED CHARGES: Regulatory assets .................................................. 1,842,939 2,005,554 Property taxes ..................................................... 59,035 59,035 Unamortized sale and leaseback costs ............................... 69,672 72,294 Other .............................................................. 54,422 51,739 ---------- ---------- 2,026,068 2,188,622 ---------- ---------- $7,669,373 $7,790,041 ========== ==========
48 OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS
(UNAUDITED) ----------- MARCH 31, DECEMBER 31, 2003 2002 ----------- ----------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ----------- ----------- (IN THOUSANDS) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding ....................................... $ 2,098,729 $ 2,098,729 Accumulated other comprehensive loss ........................... (62,548) (59,495) Retained earnings .............................................. 875,167 800,021 ----------- ----------- Total common stockholder's equity .......................... 2,911,348 2,839,255 Preferred stock not subject to mandatory redemption .............. 60,965 60,965 Preferred stock of consolidated subsidiary- Not subject to mandatory redemption ............................ 39,105 39,105 Subject to mandatory redemption ................................ 13,500 13,500 Long-term debt ................................................... 1,238,877 1,219,347 ----------- ----------- 4,263,795 4,172,172 ----------- ----------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock ............. 526,475 563,267 Short-term borrowings- Associated companies ........................................... 187 225,345 Other .......................................................... 175,197 182,317 Accounts payable- Associated companies ........................................... 173,086 145,981 Other .......................................................... 5,380 18,015 Accrued taxes .................................................... 472,115 466,064 Accrued interest ................................................. 30,646 28,209 Other ............................................................ 101,023 74,562 ----------- ----------- 1,484,109 1,703,760 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes ................................ 1,005,763 1,017,629 Accumulated deferred investment tax credits ...................... 85,292 88,449 Asset retirement obligation ...................................... 302,524 -- Nuclear plant decommissioning costs .............................. -- 280,858 Retirement benefits .............................................. 250,211 247,531 Other ............................................................ 277,679 279,642 ----------- ----------- 1,921,469 1,914,109 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2) $ 7,669,373 $ 7,790,041 =========== ===========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. 49 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ---------------------------------- 2003 2002 ------------- ------------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------- ------------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income .................................................................. $ 88,805 $ 66,637 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization ............................ 108,385 75,730 Nuclear fuel and lease amortization .................................... 7,106 11,402 Deferred income taxes, net ............................................. 7,683 (7,380) Investment tax credits, net ............................................ (3,704) (3,449) Cumulative effect of accounting change (Note 5) ........................ (54,109) -- Receivables ............................................................ (29,909) 64,148 Materials and supplies ................................................. (1,298) (1,642) Accounts payable ....................................................... 14,470 (18,295) Accrued taxes .......................................................... 6,051 56,884 Accrued interest ....................................................... 2,437 6,237 Deferred lease costs ................................................... 31,683 31,683 Prepayments and other .................................................. (14,893) 16,095 Other .................................................................. (9,190) (30,539) --------- --------- Net cash provided from operating activities .......................... 153,517 267,511 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt ......................................................... -- 104,985 Short-term borrowings, net ............................................. -- 40,306 Redemptions and Repayments- Long-term debt ......................................................... (19,493) (89,547) Short-term borrowings, net ............................................. (232,278) -- Dividend Payments Common stock ........................................................... (13,000) (101,200) Preferred stock ........................................................ (659) (2,597) --------- --------- Net cash used for financing activities ............................... (265,430) (48,053) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions ....................................................... (68,367) (30,344) Notes receivable from associated companies, net .......................... 173,250 (138,181) Other .................................................................... 838 1,972 --------- --------- Net cash provided from (used for) investing activities ............... 105,721 (166,553) --------- --------- Net Increase (decrease) in cash and cash equivalents ........................ (6,192) 52,905 Cash and cash equivalents at beginning of period ............................ 20,512 4,588 --------- --------- Cash and cash equivalents at end of period .................................. $ 14,320 $ 57,493 ========= =========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. 50 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of Ohio Edison Company: We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the quarters ended March 31, 2003 and 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained a reference to the Company's restatement of its previously issued consolidated financial statements for the year ended December 31, 2002 as discussed in Note 1(M) to those consolidated financial statements) dated February 28, 2003, except as to Note 1(M), which is as of August 18, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003, except as to Note 1, which is as of August 18, 2003 51 OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE and Penn (OE Companies) also provide generation services to those customers electing to retain them as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under OE's transition plan. The OE Companies have unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy is restating its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003 and 2002. The restatements reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2006 for OE. FirstEnergy and the Ohio utilities amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, versus the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. The amortization expense under the revised method (see Note 1) decreased by $8 million for the three months ended June 30, 2002 and increased by $3 million for the three months ended June 30, 2003. RESULTS OF OPERATIONS Earnings on common stock in the first quarter of 2003 increased to $88.1 million from $64.0 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $31.7 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $57.1 million in the first three months of 2003, compared to $66.6 million for the same period of 2002. Lower results in the first quarter of 2003 reflect higher operating expenses -- primarily nuclear operating costs, employee benefit costs and depreciation and amortization. Partially offsetting these effects were higher revenues due to colder weather, increased sales to FES and reduced financing costs, compared with the first quarter of 2002, as well as the absence of adjustments reflected in the first quarter of 2002 for OE's low income housing investments. Operating revenues increased by $34.9 million or 4.9% in the first quarter of 2003 compared with the same period in 2002. The higher revenues resulted from increased distribution deliveries to residential and commercial customers due to colder temperatures and additional sales revenues to FES, which were partially offset by lower generation kilowatt-hour sales to retail customers. Kilowatt-hour sales to retail customers declined by 1.4% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $13.6 million. Electric generation services provided by alternative suppliers as a percent of total sales delivered in OE's franchise area increased to 24.0% in the first quarter of 2003 from 17.1% in the first quarter of 2002. Distribution deliveries increased 7.6% in the first quarter of 2003 compared with the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). This increased revenues from electricity throughput by $37.6 million in the first quarter of 2003 from the same quarter of the prior year. Approximately 52 70% of the increase reflected higher volumes with the remainder due to higher unit prices. Distribution deliveries benefited from substantially higher residential and commercial demand, due in large part to colder temperatures, that was moderated by the continued effect of a sluggish economy and its impact on demand by industrial customers in OE's franchise area. Partially offsetting the increase in revenues from distribution deliveries were Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers -- $6.3 million of additional credits in the first quarter of 2003 from the same period last year. These reductions in revenues are deferred for future recovery under OE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers increased by $17.3 million (primarily to FES) in the first quarter of 2003 compared to the same quarter of 2002, due to higher market prices. Increased wholesale revenues occurred despite a reduction in kilowatt-hour sales in the first quarter of 2003 from the same quarter last year, due a 9.9% reduction in available nuclear generation from Beaver Valley Unit 1 as a result of its refueling outage that began on March 8, 2003. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the same quarter of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES ---------------------------------------------------- INCREASE (DECREASE) Electric Generation: Retail.................................. (1.4)% Wholesale............................... (7.1)% ---------------------------------------------------- TOTAL ELECTRIC GENERATION SALES........... (4.0)% ==================================================== Distribution Deliveries: Residential............................. 12.2% Commercial.............................. 8.7% Industrial.............................. 2.1% --------------------------------------------------- TOTAL DISTRIBUTION DELIVERIES............. 7.6% ===================================================
Operating Expenses and Taxes Total operating expenses and taxes increased by $72.2 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES ------------------------------------------------------------------ INCREASE (DECREASE) (IN MILLIONS) (REVISED) Fuel............................................. $ (1.4) Purchased power costs............................ 2.3 Nuclear operating costs.......................... 30.1 Other operating costs............................ 10.7 -------------------------------------------------------------- TOTAL OPERATION AND MAINTENANCE EXPENSES....... 41.7 Provision for depreciation and amortization...... 32.6 General taxes.................................... 2.9 Income taxes..................................... (5.0) --------------------------------------------------------------- TOTAL OPERATING EXPENSES AND TAXES............. $72.2 ===============================================================
Lower fuel costs in the first quarter of 2003, compared with the same quarter of 2002, resulted from reduced nuclear generation. The increased purchased power costs reflected additional kilowatt-hour purchases offset in part by lower unit costs. Higher nuclear operating costs occurred in large part due to the refueling outage at Beaver Valley Unit 1 (100% ownership) in the first quarter of 2003 compared with refueling outage costs at Beaver Valley Unit 2 (55.6% ownership) in the first quarter of 2002. The increase in other operating costs reflects higher employee benefit costs and increased uncollectible customer accounts. Charges for depreciation and amortization increased by $32.6 million in the first quarter of 2003 compared to the first quarter of 2002 primarily from two factors - increased amortization of the Ohio transition regulatory assets ($33.8 million) and reduced transition plan tax-related deferrals ($6.3 million) in 2003. Partially offsetting these increases were higher shopping incentive deferrals ($6.6 million) and lower charges resulting from the implementation of SFAS 143 ($4.7 million), including revised service life assumptions for generating plants ($1.0 million). 53 General taxes increased in the first quarter of 2003 from the same quarter of last year principally due to higher kilowatt-hour taxes in Ohio as the result of increased kilowatt-hour deliveries. Other Income Other income increased by $13.0 million in the first quarter of 2003 from the same period last year, primarily due to the absence in the first quarter of 2003 of adjustments recorded in the first quarter of 2002 related to OE's low income housing investments. Net Interest Charges Net interest charges continued to trend lower, decreasing by $14.7 million in the first quarter of 2003 from the same period last year, reflecting redemptions and refinancings since the first quarter of 2002. OE's net debt redemptions totaled $13.0 million during the first quarter of 2003, which will result in annualized savings of $1.1 million. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net income of $31.7 million. OE identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $133.7 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25.2 million. The asset retirement obligation (ARO) liability at the date of adoption was $297.6 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, OE had recorded decommissioning liabilities of $292.4 million, including unrealized gains on the decommissioning trust funds of $10.6 million. Penn expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, OE recognized a regulatory liability of $10.6 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for Penn. The remaining cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54.1 million increase to income, or $31.7 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY OE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, OE expects to meet its contractual obligations with cash from operations. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, OE had $14.3 million of cash and cash equivalents, compared with $20.5 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided by operating activities during the first quarter of 2003, compared with the corresponding period in 2002 were as follows:
OPERATING CASH FLOWS 2003 2002 ------------------------------------------------------------ (IN MILLIONS) Cash earnings (1).................... $154 $143 Working capital and other............ -- 125 ------------------------------------------------------------ Total................................ $154 $268 ============================================================
(1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. 54 Net cash from operating activities decreased $114 million due to a $124 million increase in funds used for working capital -- that decrease was offset in part by a $11 million increase in cash earnings. The increase in working capital and other primarily reflects higher accounts receivable from associated companies in the first quarter of 2003 compared with corresponding amounts in the first quarter of 2002 ($81 million). A change in accrued tax liabilities also contributed $52 million to the increase in working capital primarily due to a $48 million increase in tax payments in the first quarter of 2003 compared with the first quarter of 2002. Cash Flows From Financing Activities In the first quarter of 2003, net cash used for financing activities increased to $265 million from $48 million in the same period last year. The increase resulted from the absence of new financing and a reduction of debt (primarily short-term borrowings from associated companies) partially offset by reduced dividends to FirstEnergy. OE had approximately $279.1 million of cash and temporary investments and approximately $175.4 million of short-term indebtedness as of March 31, 2003. Available borrowing capability under bilateral bank facilities totaled $34.0 million as of March 31, 2002. OE had the capability to issue $1.7 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests OE could issue up to $3.0 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2003. On April 21, 2003, OE completed a $325 million debt refinancing transaction that included two tranches -- $175 million of 4.00% five year notes and $150 million of 5.45% twelve year notes. The net proceeds will be used to redeem approximately $220 million of outstanding OE first mortgage bonds having a weighted average cost of 7.99%, with the remainder to be used to pay down short-term debt. Cash Flows From Investing Activities Net cash flows received from investing activities totaled $106 million in the first quarter of 2003, compared to a net use of funds of $167 million for the same period of 2002. The $273 million increase in funds from investing activities resulted from payments received on notes from associated companies, offset in part by additional capital expenditures. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $113 million, including $17 million for nuclear fuel. OE has additional requirements of approximately $234 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including OE. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." 55 Other Obligations Obligations not included on OE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $713 million. EQUITY PRICE RISK Included in OE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $151 million and $148 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $15 million reduction in fair value as of March 31, 2003. OUTLOOK Beginning in 2001, OE's customers were able to select alternative energy suppliers. OE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's Ohio customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO), Pennsylvania Public Utility Commission and the Federal Energy Regulatory Commission, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined $162.7 million to $1.8 billion on March 31, 2003 from the balance as of December 31, 2002, with $10.6 million of the decrease related to the cumulative entry adopting SFAS 143 at Penn and the balance of the reduction resulting from recovery of transition plan regulatory assets. All of the OE Companies' regulatory assets are expected to continue to be recovered under the provisions of their respective transition plan and rate restructuring plan. The OE Companies' regulatory assets are as follows:
REGULATORY ASSETS AS OF --------------------------------------------------------- MARCH 31, DECEMBER 31, Company 2003 2002 --------------------------------------------------------- (IN MILLIONS) OE......................... $1,765.1 $1,848.7 Penn....................... 77.8 156.9 --------------------------------------------------------- Consolidated Total...... $1,842.9 $2,005.6 =========================================================
As part of OE's Ohio transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. OE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. In 2003, the total peak load forecasted for customers electing to stay with OE, including the 560 MW of low cost supply and the load served by OE's affiliate is 5,820 MW. Environmental Matters OE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from OE's Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2C - Environmental Matters). OE continues to evaluate its compliance plans and other compliance options. 56 Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. OE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The civil complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures they may be required, may have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. OE believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. Management is unable to predict the ultimate outcome of this matter. The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition. The effects of compliance on OE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent OE competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. OE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. SIGNIFICANT ACCOUNTING POLICIES OE prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect OE's financial results. All of the OE Companies' 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 57 are similarly reviewed with their risks and uncertainties reflecting those specific factors. The OE Companies' more significant accounting policies are described below. Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on the costs that the regulatory agencies determine the OE Companies 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 Ohio and Pennsylvania, a significant amount of regulatory assets have been recorded. As of March 31, 2003, the OE Companies' regulatory assets totaled $1.8 billion. OE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition The OE Companies follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: - Net energy generated or purchased for retail load - Losses of energy over distribution lines - Allocations to distribution companies within the FirstEnergy system - Mix of kilowatt-hour usage by residential, commercial and industrial customers - Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends 58 have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In developing OE's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on OE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). OE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, OE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, the OE Companies recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (OE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. OE currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. OE currently consolidates the majority of these entities and believe it will continue to consolidate following the adoption of FIN 46. In addition to the entities it is currently consolidating, OE believes that the PNBV Capital Trust, which was used to acquire a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Perry Plant and Beaver Valley Unit 2, would require consolidation as a VIE under FIN 46. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. 59 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------- 2003 2002 ---------- ---------- RESTATED RESTATED (See Note 1) (See Note 1) (IN THOUSANDS) OPERATING REVENUES ................................................................. $ 419,771 $ 433,277 ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel ............................................................................ 12,659 17,270 Purchased power ................................................................. 136,345 139,436 Nuclear operating costs ......................................................... 55,361 63,617 Other operating costs ........................................................... 63,009 58,047 ---------- ---------- Total operation and maintenance expenses .................................... 267,374 278,370 Provision for depreciation and amortization ..................................... 51,357 52,471 General taxes ................................................................... 39,713 38,746 Income taxes .................................................................... 7,316 6,165 ---------- ---------- Total operating expenses and taxes .......................................... 365,760 375,752 ---------- ---------- OPERATING INCOME ................................................................... 54,011 57,525 OTHER INCOME ....................................................................... 4,741 5,241 ---------- ---------- INCOME BEFORE NET INTEREST CHARGES ................................................. 58,752 62,766 ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt ...................................................... 40,640 46,995 Allowance for borrowed funds used during construction ........................... (2,167) (749) Other interest expense (credit) ................................................. 31 (529) Subsidiary's preferred dividend requirements .................................... 4,950 2,150 ---------- ---------- Net interest charges ........................................................ 43,454 47,867 ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ............................... 15,298 14,899 Cumulative effect of accounting change (Net of income taxes of $30,168,000) (Note 5) 42,378 -- ---------- ---------- NET INCOME ......................................................................... 57,676 14,899 PREFERRED STOCK DIVIDEND REQUIREMENTS .............................................. (759) 6,556 ---------- ---------- EARNINGS ATTRIBUTABLE TO COMMON STOCK .............................................. $ 58,435 $ 8,343 ========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. 60 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ---------- ------------ RESTATED RESTATED (See Note 1) (See Note 1) (IN THOUSANDS) ASSETS UTILITY PLANT: In service ............................................................ $4,114,337 $4,045,465 Less--Accumulated provision for depreciation .......................... 1,834,329 1,824,884 ---------- ---------- 2,280,008 2,220,581 Construction work in progress- Electric plant ...................................................... 164,966 153,104 Nuclear fuel ........................................................ 44,406 45,354 ---------- ---------- 209,372 198,458 ---------- ---------- 2,489,380 2,419,039 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust ............................................ 416,836 435,907 Nuclear plant decommissioning trusts .................................. 234,855 230,527 Long-term notes receivable from associated companies .................. 102,860 102,978 Other ................................................................. 20,914 21,004 ---------- ---------- 775,465 790,416 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents ............................................. 826 30,382 Receivables- Customers ........................................................... 14,184 11,317 Associated companies ................................................ 63,946 74,002 Other (less accumulated provisions of $1,015,000 for uncollectible... accounts at both dates) ........................................... 126,322 134,375 Notes receivable from associated companies ............................ 565 447 Materials and supplies, at average cost- Owned ............................................................... 18,356 18,293 Under consignment ................................................... 38,159 38,094 Prepayments and other ................................................. 2,445 4,217 ---------- ---------- 264,803 311,127 ---------- ---------- DEFERRED CHARGES: Regulatory assets ..................................................... 1,170,431 1,191,804 Goodwill .............................................................. 1,693,629 1,693,629 Property taxes ........................................................ 79,430 79,430 Other ................................................................. 25,065 24,798 ---------- ---------- 2,968,555 2,989,661 ---------- ---------- $6,498,203 $6,510,243 ========== ==========
61 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ----------- ------------ RESTATED RESTATED (See Note 1) (See Note 1) (IN THOUSANDS) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 105,000,000 shares - 79,590,689 shares outstanding......................................... $ 981,962 $ 981,962 Accumulated other comprehensive loss.................................... (46,818) (44,284) Retained earnings....................................................... 320,782 262,323 ----------- ----------- Total common stockholder's equity................................... 1,255,926 1,200,001 Preferred stock- Not subject to mandatory redemption..................................... 96,404 96,404 Subject to mandatory redemption......................................... 5,019 5,021 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000 Long-term debt............................................................ 1,972,400 1,975,001 ----------- ----------- 3,429,749 3,376,427 ----------- ----------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 343,199 388,190 Accounts payable- Associated companies.................................................... 229,544 267,664 Other................................................................... 8,574 14,583 Notes payable to associated companies..................................... 321,828 288,583 Accrued taxes............................................................. 129,157 126,261 Accrued interest.......................................................... 60,611 51,767 Other..................................................................... 98,294 124,624 ------------- ------------ 1,191,207 1,261,672 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 438,761 407,297 Accumulated deferred investment tax credits............................... 69,601 70,803 Nuclear plant decommissioning costs....................................... -- 242,511 Asset retirement obligation............................................... 242,599 -- Retirement benefits....................................................... 173,765 171,968 Lease market valuation liability.......................................... 773,800 788,800 Other..................................................................... 178,721 190,765 ------------ ------------ 1,877,247 1,872,144 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)........................... ----------- ----------- $6,498,203 $6,510,243 ========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets. 62 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------------ 2003 2002 ----------- ---------- RESTATED RESTATED (See Note 1) (See Note 1) (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................. $ 57,676 $ 14,899 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization......................... 51,357 52,471 Nuclear fuel and lease amortization................................. 5,044 5,990 Other amortization.................................................. (4,613) (3,892) Deferred income taxes, net.......................................... 33,804 822 Investment tax credits, net......................................... (1,202) (1,043) Receivables......................................................... 15,242 (1,484) Materials and supplies.............................................. (128) (1,366) Accounts payable.................................................... (44,129) 18,322 Cumulative effect of accounting change.............................. (72,547) -- Accrued taxes....................................................... 2,896 84 Accrued interest.................................................... 8,844 5,569 Prepayments and other............................................... 1,772 22,508 Deferred rents and sale/leaseback................................... (41,603) (123) Other............................................................... (7,593) (25,235) ----------- ---------- Net cash provided from operating activities....................... 4,820 87,522 ----------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net............................................ 33,245 75,484 Redemptions and Repayments- Preferred Stock....................................................... -- (100,000) Long-term debt........................................................ (45,103) (94) Dividend Payments- Preferred stock....................................................... (1,865) (5,252) ----------- ---------- Net cash used for financing activities............................ (13,723) (29,862) ----------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions...................................................... (31,218) (36,470) Capital trust investments............................................... 19,071 -- Other................................................................... (8,506) (6,224) ----------- ---------- Net cash used for investing activities............................ (20,653) (42,694) ----------- ---------- Net increase (decrease) in cash and cash equivalents....................... (29,556) 14,966 Cash and cash equivalents at beginning of period .......................... 30,382 296 ----------- ---------- Cash and cash equivalents at end of period................................. $ 826 $ 15,262 =========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. 63 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the quarters ended March 31, 2003 and 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for goodwill in 2002 as discussed in Note 1(D) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002 as discussed in Note 1(M) to those consolidated financial statements) dated August 18, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003, except as to Note 1, which is as of August 18, 2003 64 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain them as their power supplier. CEI provides power directly to alternative energy suppliers under CEI's transition plan. CEI has unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES -- an affiliated company. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy is restating its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003 and 2002. The restatements reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2009 for CEI. FirstEnergy and the Ohio utilities amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, versus the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. The amortization expense under the revised method (see Note 1) increased by $24 million and $24.8 million for the three months ended June 30, 2002 and 2003, respectively. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of CEI, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI had previously entered into sale-leaseback arrangements. CEI recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant were recorded as regulatory assets because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $611 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS 142. The total above market lease obligation of $457 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's amortization schedule for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI. 65 RESULTS OF OPERATIONS Earnings on common stock in the first quarter of 2003 increased to $58.4 million from income of $8.3 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $42.4 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $15.3 million in the first quarter of 2003, compared to $14.9 million for the same period of 2002. Operating revenues decreased by $13.5 million or 3.1% in the first quarter of 2003 from the same period in 2002. The lower revenues resulted from reduced kilowatt-hour sales, which were partially offset by the effects of colder weather on distribution deliveries to residential and commercial customers. Kilowatt-hour sales to retail customers declined by 4.3% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $6.6 million. Electric generation services provided by alternative suppliers as a percent of total sales deliveries in CEI's franchise area increased to 37.6% in the first quarter of 2003 from 28.5% in the first quarter of 2002. Distribution deliveries increased 10.5% in the first quarter of 2003 compared to the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). As a result, revenues from electricity throughput increased by $15.5 million in the first quarter of 2003 from the same quarter of the prior year. The increase reflected higher volumes, offset in part by lower unit prices. Distribution deliveries to residential and commercial customers benefited from colder than normal weather, while a substantial increase in distribution deliveries to industrial customers, despite the continued effect of a sluggish economy, resulted from an expansion of steel production in the franchise area. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, reduced operating revenues -- $5.8 million in the first quarter of 2003 compared with the corresponding period of 2002. These revenue reductions are deferred for future recovery under CEI's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $10.7 million (primarily to FES) in the first quarter of 2003 compared with the first quarter of 2002, due to reduced nuclear generation from the extended outage of the Davis-Besse Plant (see Davis-Besse Restoration). Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES ---------------------------------------------------- INCREASE (DECREASE) Electric Generation: Retail.................................. (4.3)% Wholesale............................... (17.8)% ---------------------------------------------------- TOTAL ELECTRIC GENERATION SALES........... (11.3)% ==================================================== Distribution Deliveries: Residential............................. 12.9% Commercial.............................. 7.0% Industrial.............................. 10.9% ---------------------------------------------------- TOTAL DISTRIBUTION DELIVERIES............. 10.5% ====================================================
Operating Expenses and Taxes Total operating expenses and taxes decreased by $9.9 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES --------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) (REVISED) Fuel............................................ $(4.6) Purchased power costs........................... (3.1) Nuclear operating costs......................... (8.3) Other operating costs........................... 5.0 --------------------------------------------------------------- TOTAL OPERATION AND MAINTENANCE EXPENSES...... (11.0) Provision for depreciation and amortization..... (1.1) General taxes................................... 1.0 Income taxes.................................... 1.2 --------------------------------------------------------------- TOTAL OPERATING EXPENSES AND TAXES............ $(9.9) ===============================================================
66 Lower fuel costs in the first quarter of 2003, compared with the first quarter of 2002 resulted from reduced nuclear generation (down 21%). The lower purchased power costs reflected reduced unit costs offset in part by additional kilowatt-hours purchased. Two scheduled refueling outages in the first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first quarter of 2003 more than offset incremental costs associated with the extended outage of Davis-Besse, producing the lower nuclear operating costs. The increase in other operating costs resulted in part from higher employee benefit costs. The decrease in depreciation and amortization charges in the first quarter of 2003, compared with the first quarter of 2002 was attributable to several factors - higher shopping incentive deferrals ($5.8 million) and lower charges resulting from the implementation of SFAS 143 ($3.0 million), including revised service life assumptions for generating plants ($4.0 million). Partially offsetting these decreases were increased amortization of regulatory assets being recovered under CEI's transition plan ($1.5 million) and recognition of depreciation on three fossil plants ($8.1 million), which had been held pending sale in the first quarter of 2002 but were subsequently retained by FirstEnergy in the fourth quarter of 2002. Net Interest Charges Net interest charges continued to trend lower, decreasing by $0.5 million in the first quarter of 2003 from the same quarter last year, reflecting redemptions and refinancings since the end of the first quarter of 2002. CEI's net debt redemptions totaled $15.0 million during the first quarter of 2003 which will result in annualized savings of $1.2 million. Cumulative Effect of Accounting Changes Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded an after-tax credit to net income of $42.4 million. CEI identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $6.8 million. The asset retirement obligation liability at the date of adoption was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, CEI had recorded decommissioning liabilities of $242.5 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $72.5 million increase to income, or $42.4 million net of income taxes. Preferred Stock Dividend Requirements Preferred stock dividend requirements decreased $7.3 million in the first quarter of 2003, compared to the same period last year, principally due to optional redemptions of preferred stock in 2002. CAPITAL RESOURCES AND LIQUIDITY CEI's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, CEI expects to meet its contractual obligations with cash from operations. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, CEI had $0.8 million of cash and cash equivalents, compared with $30.4 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the first quarter of 2003, compared with the first quarter of 2002 were as follows: 67
OPERATING CASH FLOWS 2003 2002 ------------------------------------------------------------- (IN MILLIONS) Cash earnings (1).................... $ 52 $ 50 Working capital and other............ (47) 38 ------------------------------------------------------------- Total................................ $ 5 $ 88 =============================================================
(1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $83 million due to an $85 million decrease in working capital - that decrease was offset in part by a $2 million increase in cash earnings. The largest factors contributing to the increase in working capital and other were lower accounts payable from associated companies in the first quarter of 2003 compared with corresponding amounts in the first quarter of 2002 ($68 million). Cash Flows From Financing Activities Net cash used for financing activities declined $16 million in the first quarter of 2003 from the first quarter of 2002. The decrease in funds used for financing activities primarily reflected lower security redemptions and repayments, which were partially offset by a net reduction in short-term borrowings. CEI had about $1.4 million of cash and temporary investments and approximately $321.8 million of short-term indebtedness as of March 31, 2003. CEI had the capability to issue $545.5 million of additional first mortgage bonds on the basis of property additions and retired bonds. CEI has no restrictions on the issuance of preferred stock. Cash Flows From Investing Activities Net cash used for investing activities decreased $22 million in the first quarter of 2003 from the same quarter of 2002 due to a reduction in the Shippingport Capital Trust investment and lower capital expenditures. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $85 million, including $9 million for nuclear fuel. CEI has additional requirements of approximately $101 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including CEI. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." 68 Other Obligations Obligations not included on CEI's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $157 million. CEI sells substantially all of its retail customer receivables, which provided $96 million of off-balance sheet financing as of March 31, 2003. EQUITY PRICE RISK Included in CEI's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $117 million and $119 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of March 31, 2003. OUTLOOK Beginning in 2001, CEI's customers were able to select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the PUCO and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets decreased $21.4 million to $1,170.4 million as of March 31, 2003 from the balance as of December 31, 2002. All of CEI's regulatory assets are expected to continue to be recovered under the provisions of its transition plan. As part of CEI's Ohio transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. CEI's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical 69 issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. CEI's ownership share is 51.38% of those expenses. It is anticipated that an additional $13.7 million in maintenance costs will be spent during the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. Environmental Matters CEI believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from its generating facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2 - Environmental Matters). CEI continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. CEI has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. CEI's total accrued liabilities were approximately $2.5 million as of March 31, 2003. The effects of compliance on CEI with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent CEI competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. CEI believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings related to CEI's normal business operations are pending against CEI, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES CEI prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect CEI's financial results. All of CEI's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. CEI's more significant accounting policies are described below. 70 Regulatory Accounting CEI is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine CEI is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio a significant amount of regulatory assets have been recorded. As of March 31, 2003, CEI's regulatory assets totaled $1,170.4 million. CEI regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition CEI follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: - Net energy generated or purchased for retail load - Losses of energy over distribution lines - Allocations to distribution companies within the FirstEnergy system - Mix of kilowatt-hour usage by residential, commercial and industrial customers - Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, 71 FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In developing CEI's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on CEI's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). CEI uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, CEI includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, CEI recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, CEI evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur, CEI would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. CEI's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in CEI's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of March 31, 2003, CEI had approximately $1.7 billion of goodwill. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (CEI's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. CEI currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. CEI currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities CEI is currently consolidating is the Shippingport Capital Trust which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., an affiliated company. 72 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------- 2003 2002 ---------- ---------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ---------- ---------- (IN THOUSANDS) OPERATING REVENUES ................................................................. $ 231,822 $ 252,567 ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel ............................................................................ 7,681 11,391 Purchased power ................................................................. 74,251 82,404 Nuclear operating costs ......................................................... 64,555 73,673 Other operating costs ........................................................... 34,037 27,184 ---------- ---------- Total operation and maintenance expenses .................................... 180,524 194,652 Provision for depreciation and amortization ..................................... 35,640 37,768 General taxes ................................................................... 15,008 13,748 Income taxes (benefit) .......................................................... (4,827) (4,289) ---------- ---------- Total operating expenses and taxes .......................................... 226,345 241,879 ---------- ---------- OPERATING INCOME ................................................................... 5,477 10,688 OTHER INCOME ....................................................................... 3,100 4,343 ---------- ---------- INCOME BEFORE NET INTEREST CHARGES ................................................. 8,577 15,031 ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt ...................................................... 11,815 15,872 Allowance for borrowed funds used during construction ........................... (1,306) (428) Other interest expense (credit) ................................................. (532) (735) ---------- ---------- Net interest charges ........................................................ 9,977 14,709 ---------- ---------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ........................ (1,400) 322 Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 5) 25,550 -- ---------- ---------- NET INCOME ......................................................................... 24,150 322 PREFERRED STOCK DIVIDEND REQUIREMENTS .............................................. 2,205 4,724 ---------- ---------- EARNINGS (LOSS) ATTRIBUTABLE TO COMMON STOCK ....................................... $ 21,945 $ (4,402) ========== ==========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. 73 THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ------------- ------------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------- ------------- (IN THOUSANDS) ASSETS UTILITY PLANT: In service................................................................ $ 1,655,389 $ 1,600,860 Less--Accumulated provision for depreciation.............................. 723,821 706,772 ------------- ------------- 931,568 894,088 ------------- ------------- Construction work in progress- Electric plant.......................................................... 110,267 104,091 Nuclear fuel............................................................ 30,464 33,650 ------------- ------------- 140,731 137,741 ------------- ------------- 1,072,299 1,031,829 ------------- ------------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 223,335 240,963 Nuclear plant decommissioning trusts...................................... 179,511 174,514 Long-term notes receivable from associated companies...................... 162,109 162,159 Other..................................................................... 2,172 2,236 ------------- ------------- 567,127 579,872 ------------- ------------- CURRENT ASSETS: Cash and cash equivalents................................................. 1,445 20,688 Receivables- Customers............................................................... 5,640 4,711 Associated companies.................................................... 44,275 55,245 Other................................................................... 4,570 6,778 Notes receivable from associated companies................................ 6,452 1,957 Materials and supplies, at average cost- Owned................................................................... 13,768 13,631 Under consignment....................................................... 23,587 22,997 Prepayments and other..................................................... 8,576 3,455 ------------- ------------- 108,313 129,462 ------------- ------------- DEFERRED CHARGES: Regulatory assets......................................................... 557,420 578,243 Goodwill.................................................................. 504,522 504,522 Property taxes............................................................ 23,429 23,429 Other..................................................................... 14,641 14,257 ------------- ------------- 1,100,012 1,120,451 ------------- ------------- $ 2,847,751 $ 2,861,614 ============= =============
74 THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS
(UNAUDITED) MARCH 31, DECEMBER 31, 2003 2002 ------------- ------------ RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------- ------------ (IN THOUSANDS) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity- Common stock, $5 par value, authorized 60,000,000 shares - 39,133,887 shares outstanding......................................... $ 195,670 $ 195,670 Other paid-in capital................................................... 428,559 428,559 Accumulated other comprehensive loss.................................... (20,535) (20,012) Retained earnings....................................................... 100,723 78,778 ------------- ------------ Total common stockholder's equity................................... 704,417 682,995 Preferred stock not subject to mandatory redemption....................... 126,000 126,000 Long-term debt............................................................ 556,080 557,265 ------------- ------------ 1,386,497 1,366,260 ------------- ------------ CURRENT LIABILITIES: Currently payable long-term debt.......................................... 115,755 189,355 Accounts payable- Associated companies.................................................... 120,483 171,862 Other................................................................... 6,100 9,338 Notes payable to associated companies..................................... 248,045 149,653 Accrued taxes............................................................. 40,712 34,676 Accrued interest.......................................................... 14,978 16,377 Other..................................................................... 77,616 82,062 ------------- ------------ 623,689 653,323 ------------- ------------ DEFERRED CREDITS: Accumulated deferred income taxes......................................... 178,254 158,279 Accumulated deferred investment tax credits............................... 26,941 27,455 Nuclear plant decommissioning costs....................................... -- 179,587 Asset retirement obligation............................................... 166,858 -- Retirement benefits....................................................... 83,324 82,553 Lease market valuation liability.......................................... 311,050 317,200 Other..................................................................... 71,138 76,957 ------------- ------------ 837,565 842,031 ------------- ------------ COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ------------- ------------ $ 2,847,751 $ 2,861,614 ============= ============
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets. 75 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------------ 2003 2002 ------------ ------------ RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) ------------ ------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 24,150 $ 322 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization.............................. 35,640 37,768 Nuclear fuel and lease amortization...................................... 2,768 3,573 Deferred income taxes, net............................................... 19,130 1,242 Investment tax credits, net.............................................. (514) (526) Receivables.............................................................. 12,249 11,622 Materials and supplies................................................... (727) (651) Accounts payable......................................................... (53,917) 1,161 Cumulative effect of accounting change................................... (43,751) -- Accrued taxes............................................................ 5,745 (5,710) Accrued interest......................................................... (1,399) (2,030) Prepayments and other.................................................... (5,121) 9,987 Deferred rents and sale/leaseback........................................ (7,672) 18,728 Other.................................................................... (16,532) (9,721) --------- --------- Net cash provided from (used for) operating activities................. (29,951) 65,765 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net................................................. 98,392 68,998 Redemptions and Repayments- Preferred stock............................................................ -- (85,299) Long-term debt............................................................. (73,600) (94) Dividend Payments- Common stock............................................................... -- (5,600) Preferred stock............................................................ (2,211) (3,425) --------- --------- Net cash provided from (used for) financing activities................. 22,581 (25,420) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (17,242) (25,559) Loans to associated companies................................................ (4,445) (6,301) Capital trust investments.................................................... 17,628 (57) Other........................................................................ (7,814) (6,121) --------- --------- Net cash provided from (used for) investing activities................. (11,873) (38,038) --------- --------- Net increase (decrease) in cash and cash equivalents............................ (19,243) 2,307 Cash and cash equivalents at beginning of period................................ 20,688 302 --------- --------- Cash and cash equivalents at end of period...................................... $ 1,445 $ 2,609 ========= =========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. 76 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of The Toledo Edison Company: We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31, 2003, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the quarters ended March 31, 2003 and 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for goodwill in 2002 as discussed in Note 1(D) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002 as discussed in Note 1(M) to those consolidated financial statements) dated August 18, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003, except as to Note 1, which is as of August 18, 2003 77 THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE conducts business in portions of Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain them as their power supplier. TE provides power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under TE's transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of TE are provided by FES - an affiliated company. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy is restating its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003 and 2002. The restatements reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2007 for TE. FirstEnergy and the Ohio utilities amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, versus the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. The amortization expense under the revised method (see Note 1) increased by $16.4 million and $15.4 million for the three months ended June 30, 2002 and 2003, respectively. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE had previously entered into sale-leaseback arrangements. and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant were recorded as regulatory assets because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $111 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS 142. The total above market lease obligation of $298 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in TE's amortization schedule for regulatory assets and amortized through the end of the recovery period - approximately 2007 for TE. 78 RESULTS OF OPERATIONS Earnings on common stock in the first quarter of 2003 increased to $21.9 million from a loss of $4.4 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $25.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Loss before the cumulative effect was $1.4 million in the first quarter of 2003, compared to net income of $0.3 million for the same period of 2002. Improved results in the first quarter of 2003 reflected reduced financing costs and lower operating expenses. Substantially offsetting these improvements were lower operating revenues from reduced kilowatt-hour sales. Operating revenues decreased by $20.7 million or 8.2% in the first quarter of 2003 from the same period in 2002. The lower revenues resulted from reduced kilowatt-hour sales which were partially offset by the effects of colder weather on distribution deliveries to residential and commercial customers. Kilowatt-hour sales to retail customers declined by 3.5% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $11.6 million. Electric generation services provided by alternative suppliers as a percent of total sales deliveries in TE's franchise area increased to 21.8% in the first quarter of 2003 from 14.4% in the first quarter of 2002. Distribution deliveries increased 5.8% in the first quarter of 2003 compared to the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). As a result, revenues from electricity throughput increased by $20.7 million in the first quarter of 2003 from the first quarter of 2002. The increase reflected higher unit prices, which accounted for two-thirds of the increase and higher volumes. Distribution deliveries benefited from substantially higher residential and commercial demand, due in larger part to colder than normal weather, that was moderated by the continued effect of a sluggish economy and its impact on demand by industrial customers in TE's franchise area. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, reduced operating revenues by $2.2 million in the first quarter of 2003 compared with the same period last year. These revenue reductions are deferred for future recovery under TE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $21.0 million (primarily to FES) in the first quarter of 2003 compared with the first quarter of 2002, due to reduced nuclear generation from the extended outage of the Davis-Besse Plant (see Davis-Besse Restoration). Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES ---------------------------------------------------- INCREASE (DECREASE) Electric Generation: Retail................................ (3.5)% Wholesale............................. (28.1)% ---------------------------------------------------- TOTAL ELECTRIC GENERATION SALES........... (15.2)% ==================================================== Distribution Deliveries: Residential........................... 10.9% Commercial............................ 11.7% Industrial............................ 0.3% ---------------------------------------------------- TOTAL DISTRIBUTION DELIVERIES............. 5.8% ====================================================
79 Operating Expenses and Taxes Total operating expenses and taxes decreased by $15.5 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES --------------------------------------------------------------- INCREASE (DECREASE ) (IN MILLIONS) (REVISED) Fuel............................................. $ (3.7) Purchased power costs............................ (8.2) Nuclear operating costs.......................... (9.1) Other operating costs............................ 6.9 --------------------------------------------------------------- TOTAL OPERATION AND MAINTENANCE EXPENSES....... (14.1) Provision for depreciation and amortization...... (2.2) General taxes.................................... 1.3 Income taxes..................................... (0.5) --------------------------------------------------------------- TOTAL OPERATING EXPENSES AND TAXES............. $(15.5) ===============================================================
Lower fuel costs in the first quarter of 2003, compared with the same quarter of 2002, resulted from reduced nuclear generation (down 30%). The lower purchased power costs reflected fewer kilowatt-hours required for customer needs. Two scheduled refueling outages in the first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first quarter of 2003 more than offset incremental costs associated with the extended outage of Davis-Besse, producing the lower nuclear operating costs. The increase in other operating costs resulted in part from higher employee benefit costs. Charges for depreciation and amortization decreased $2.2 million in the first quarter of 2003 compared with the first quarter of 2002, attributable to several factors - higher shopping incentive deferrals ($2.2 million) and lower charges resulting from the implementation of SFAS 143 ($4.0 million), including revised service life assumptions for generating plants ($3.0 million). Nearly offsetting these decreases were increased amortization of regulatory assets being recovered under TE's transition plan ($2.5 million) and recognition of depreciation on the Bay Shore generating plant ($1.5 million), which had been held pending sale in the first quarter of 2002 but was subsequently retained by FirstEnergy in the fourth quarter of 2002. Net Interest Charges Net interest charges continued to trend lower, decreasing by $4.7 million in the first quarter of 2003 from the same period last year, reflecting security redemptions and refinancings since the end of the first quarter of 2002. TE's net debt redemptions totaled $53.4 million during the first quarter of 2003, which will result in annualized savings of $4.2 million. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $25.6 million. TE identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $41.1 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $5.5 million. The asset retirement obligation liability at the date of adoption was $172 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, TE had recorded decommissioning liabilities of $179.6 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $43.8 million increase to income, or $25.6 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY TE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, TE expects to meet its contractual obligations with cash from operations. Thereafter, TE expects to use a combination of cash from operations and funds from the capital markets. 80 Changes in Cash Position As of March 31, 2003, TE had $1.4 million of cash and cash equivalents, compared with $20.7 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by (used for) operating activities during the first quarter of 2003, compared with the corresponding period in 2002 were as follows:
OPERATING CASH FLOWS 2003 2002 ------------------------------------------------------------- (IN MILLIONS) Cash earnings (1).................... $ 30 $ 29 Working capital and other............ (60) 37 ------------------------------------------------------------- Total................................ $(30) $ 66 =============================================================
(1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash used for operating activities was $30 million in the first quarter of 2003, a $96 million change from the $66 million provided by operating activities in the first quarter of 2002. The decrease in funds from operating activities resulted from a $97 million decrease in working capital - principally reduced accounts payable (primarily to associated companies) which contributed $56.8 million to the decrease in working capital requirements. Cash Flows From Financing Activities In the first quarter of 2003, net cash provided from financing activities increased to $23 million from net cash used for financing of $25 million in the first quarter of 2002. The increase in cash provided from financing activities primarily resulted from additional short-term borrowings from associated companies and a slight reduction in security redemptions and repayments. TE had approximately $7.9 million of cash and temporary investments and approximately $248 million of short-term indebtedness as of March 31, 2003. TE is currently precluded from issuing first mortgage bonds or preferred stock based upon applicable earnings coverage tests as of March 31, 2003. Cash Flows From Investing Activities Net cash used for investing activities decreased $26 million between the first quarter of 2003 and the same quarter of 2002 due to reduced capital expenditures and a reduction in the Shippingport Capital Trust investment. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $52 million, including $9 million for nuclear fuel. TE has additional requirements of approximately $43 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including TE. 81 On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." Other Obligations Obligations not included on TE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, totaled $509 million. TE sells substantially all of its retail customer receivables, which provided $49 million of off-balance sheet financing as of March 31, 2003. EQUITY PRICE RISK Included in TE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $90 million as of March 31, 2003 and December 31, 2002. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9 million reduction in fair value as of March 31, 2003. OUTLOOK Beginning in 2001, TE's customers were able to select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's Ohio customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by The Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined $20.8 million to $557.4 million as of March 31, 2003 from the balance as of December 31, 2002, resulting from recovery of transition plan regulatory assets. As part of TE's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. TE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating 82 maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003 after completion of the additional maintenance work and regulatory reviews. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. TE's ownership share is 48.62% of those expenses. It is anticipated that an additional $13.7 million in maintenance costs will be spent during the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. Environmental Matters TE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2C - Environmental Matters). TE continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. TE believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. TE has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has total accrued liabilities of approximately $0.2 million as of March 31, 2003. 83 The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent TE competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. TE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings relayed to TE's normal business operations are pending against TE, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES TE prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect TE's financial results. All of TE's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded. As of March 31, 2003, TE's regulatory assets totaled $557.4 million. TE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition TE follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: - Net energy generated or purchased for retail load - Losses of energy over distribution lines - Allocations to distribution companies within the FirstEnergy system - Mix of kilowatt-hour usage by residential, commercial and industrial customers - Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect 84 the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In developing TE's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on TE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). TE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, TE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur, TE would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. TE's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in TE's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of March 31, 2003, TE had approximately $505 million of goodwill. 85 RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (TE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. TE currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. TE currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities TE is currently consolidating is the Shippingport Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. 86 CONTROLS AND PROCEDURES (A) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The respective registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of this report (Evaluation Date). Based on that evaluation those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention, during the period in which this quarterly report was being prepared, material information relating to the registrant and its consolidated subsidiaries by others within those entities. (B) CHANGES IN INTERNAL CONTROLS Effective June 1, 2003, the registrants implemented a new Enterprise Resource Planning (ERP) system. While the associated business process changes transform the internal control structure, management believes adequate controls have been properly integrated into the reengineering ERP-enabled processes and that internal controls will be enhanced. 87 PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (A) EXHIBITS
EXHIBIT NUMBER FIRSTENERGY AND OE 15 Letter from independent public auditors 31.1 Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 31.2 Certification letter from chief financial officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 32.1 Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. CEI AND TE 31.1 Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 31.2 Certification letter from chief financial officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 32.1 Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI nor TE have filed as an exhibit to this Form 10-Q/A any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI or TE, , but hereby agree to furnish to the Commission on request any such documents. (B) REPORTS ON FORM 8-K FIRSTENERGY- FirstEnergy filed ten reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service and the updated schedule for JCP&L rate proceedings. A report dated January 21, 2003 reported that the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information, the filing of a $2 billion shelf registration with the SEC and the status of the JCP&L rate proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L restructuring-related deferrals. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's divestiture of its Argentina operations through the abandonment of its investment resulting in a second quarter 2003 charge to net income of $63 million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information and a JCP&L rate proceedings update. A report dated May 9, 2003 reported that FirstEnergy had amended its Form 10-K for the year ended December 31, 2002 for a change in classification of a $57.1 net of tax charge with no effect on previously reported net income. A report dated May 22, 2003, reported an agreement to sell its remaining 10.1% interest in United Kingdom-based Aquila Sterling Limited, the owner of Midlands Electricity. A report dated June 5, 2003 reported updated Davis Besse information. A report dated June 11, 2003, reported a letter filed with the Pennsylvania Public Utility Commission Administrative Law Judge which voids a prior stipulation. A report dated June 27, 2003, reported signing a settlement agreement with certain the parties in its base rate case proceeding. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis Besse. 88 OE OE filed two reports on Form 8-K since March 31, 2003. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements. A report dated August 8, 2003 reported a U.S. District Court ruling with respect to the W. H. Sammis Plant under the Clean Air Act. CEI CEI filed six reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003 reported Davis-Besse information. A report dated May 1, 2003 reported an updated Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported updated Davis-Besse information. A report dated June 5, 2003 reported updated Davis Besse information. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis-Besse. TE TE filed six reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003 reported Davis-Besse information. A report dated May 1, 2003 reported an updated Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported updated Davis-Besse information. A report dated June 5, 2003 reported updated Davis Besse information. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis-Besse. 89 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. August 18, 2003 FIRSTENERGY CORP. Registrant OHIO EDISON COMPANY Registrant THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Registrant THE TOLEDO EDISON COMPANY Registrant /s/ Harvey L. Wagner ---------------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer 90