EX-13 4 l02705aexv13.txt EXHIBIT 13 EXHIBIT 13 MANAGEMENT REPORT The consolidated financial statements were prepared by the management of FirstEnergy Corp., who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, independent public accountants, have expressed an unqualified opinion on the Company's 2002 consolidated financial statements. The Company's internal auditors, who are responsible to the Audit Committee of the Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls. The Audit Committee consists of six nonemployee directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent public accountants and the internal auditors; appointment of independent accountants to conduct the normal annual audit and special purpose audits as may be required; reviewing and approving all services, including any non-audit services, performed for the Company by the independent public accountants and reviewing the related fees; and reporting to the Board of Directors the Committee's findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee reviews the independent accountants' internal quality control procedures and reviews all relationships between the independent accountants and the Company, in order to assess the auditors' independence. The Committee also reviews management's programs to monitor compliance with the Company's policies on business ethics and risk management. The Audit Committee held nine meetings in 2002. Richard H. Marsh Senior Vice President and Chief Financial Officer Harvey L. Wagner Vice President, Controller and Chief Accounting Officer 1 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of FirstEnergy Corp.: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001, prior to the revisions described in Notes 2(E) and 8, were audited by other independent auditors who have ceased operations. Those independent auditors expressed an unqualified opinion on those financials statements, in their report dated March 18, 2002. As discussed in Note 2(E) to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed in Note 2(L) and Note 2(M) to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the year ended December 31, 2002. As discussed above, the consolidated financial statements of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent auditors who have ceased operations. As described in Note 2(E) to the consolidated financial statements, the financial statements have been revised to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, which was adopted by the Company as of January 1, 2002. Additionally, as described in Note 8 to the consolidated financial statements, the Company changed the composition of its reportable segments in 2002. We audited the transitional disclosures described in Note 2(E) and the adjustments that were applied to restate the 2001 and 2000 reportable segments disclosures discussed in Note 8. In our opinion, such adjustments to the reportable segments disclosures are appropriate and have been properly applied and the transitional disclosures for 2001 and 2000 are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 consolidated financial statements of the Company other than with respect to such transitional disclosures and adjustments to the reportable segments disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 consolidated financial statements taken as a whole. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003, except as to Note 2(L), which is as of May 9, 2003, and Notes 2(M) and 8, which are as of August 18, 2003 2 The following report is a copy of a report previously issued by Arthur Andersen LLP (Andersen). This report has not been reissued by Andersen and Andersen did not consent to the incorporation by reference of this report (as included in this form 10-K/A) into any of the Company's registration statements. As discussed in Note 2(E) to the consolidated financial statements, the Company has revised its consolidated financial statements for the years ended December 31, 2001 and 2000 to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." Additionally, as discussed in Note 8 to the consolidated financial statements, the Company has revised its consolidated financial statements for the years ended December 31, 2001 and 2000 to reflect changes in the composition of its reportable segments in 2002. The Andersen report does not extend to these changes. The revisions to the 2001 and 2000 financial statements related to these transitional disclosures and the revisions that were applied to restate the 2001 and 2000 reportable segments disclosures were reported on by PricewaterhouseCoopers LLP, as stated in their report appearing herein. REPORT OF PREVIOUS INDEPENDENT PUBLIC ACCOUNTANTS TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF FIRSTENERGY CORP.: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of FirstEnergy Corp. (an Ohio corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities by adopting Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002 3 FIRSTENERGY CORP. SELECTED FINANCIAL DATA
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 1999 1998 -------------------------------- ----------- ----------- ----------- ----------- ----------- RESTATED (SEE NOTES 2(L) AND (M)) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues ............................................ $12,230,526 $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906 ----------- ----------- ----------- ----------- ----------- Income Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Changes ..................... $ 640,280 $ 654,946 $ 598,970 $ 568,299 $ 441,396 ----------- ----------- ----------- ----------- ----------- Net Income .......................................... $ 552,804 $ 646,447 $ 598,970 $ 568,299 $ 410,874 ----------- ----------- ----------- ----------- ----------- Basic Earnings per Share of Common Stock: Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change .................... $ 2.19 $ 2.85 $ 2.69 $ 2.50 $ 1.95 After Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change .............................. $ 1.89 $ 2.82 $ 2.69 $ 2.50 $ 1.82 Diluted Earnings per Share of Common Stock: Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change ..... $ 2.18 $ 2.84 $ 2.69 $ 2.50 $ 1.95 After Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change .................... $ 1.88 $ 2.81 $ 2.69 $ 2.50 $ 1.82 Dividends Declared per Share of Common Stock ........ $ 1.50 $ 1.50 $ 1.50 $ 1.50 $ 1.50 ----------- ----------- ----------- ----------- ----------- Total Assets ........................................ $34,386,353 $37,351,513 $17,941,294 $18,224,047 $18,192,177 ----------- ----------- ----------- ----------- ----------- Capitalization at December 31: Common Stockholders' Equity ...................... $ 7,050,661 $ 7,398,599 $ 4,653,126 $ 4,563,890 $ 4,449,158 Preferred Stock: Not Subject to Mandatory Redemption ............ 335,123 480,194 648,395 648,395 660,195 Subject to Mandatory Redemption ................ 428,388 594,856 161,105 256,246 294,710 Long-Term Debt* .................................. 10,872,216 12,865,352 5,742,048 6,001,264 6,352,359 ----------- ----------- ----------- ----------- ----------- Total Capitalization* .......................... $18,686,388 $21,339,001 $11,204,674 $11,469,795 $11,756,422 =========== =========== =========== =========== ===========
* 2001 includes approximately $1.4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. PRICE RANGE OF COMMON STOCK The Common Stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE" and is traded on other registered exchanges.
2002 2001 ------------------ ------------------ First Quarter High-Low ......... $39.12 $30.30 $31.75 $25.10 Second Quarter High-Low ........ 35.12 31.61 32.20 26.80 Third Quarter High-Low ......... 34.78 24.85 36.28 29.60 Fourth Quarter High-Low ........ 33.85 25.60 36.98 32.85 Yearly High-Low ................ 39.12 24.85 36.98 25.10
Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite Transactions. HOLDERS OF COMMON STOCK There were 163,423 and 162,762 holders of 297,636,276 shares of FirstEnergy's Common Stock as of December 31, 2002 and January 31, 2003, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 5A. 4 FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), 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. 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 all of the international operations (see Capital Resources and Liquidity). Prior to the GPU merger, regulated electric distribution services were provided to portions of Ohio and Pennsylvania by our wholly owned subsidiaries - Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE) with American Transmission Systems, Inc. (ATSI) providing transmission services. Following the GPU merger, regulated services are also provided through wholly owned subsidiaries - Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec) - providing electric distribution and transmission services to portions of Pennsylvania and New Jersey. 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, often under master contracts providing for the delivery of multiple energy and energy-related services. Prior to the GPU merger, competitive services were principally provided by FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG) and MARBEL Energy Corporation. Following the GPU merger, competitive services are also provided through MYR Group, Inc. RESTATEMENTS As further discussed in Note 2(M) to the Consolidated Financial Statements, the Company is restating its consolidated financial statements for the year ended December 31, 2002. The revisions principally 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 under Regulatory matters in Note 2(D), 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, OE, CEI and TE amortize these 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 generally accepted accounting principles (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, 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 period through the end of 2009. 5 After giving effect to the restatement, total transition cost amortization including above market leases) is expected to approximate the following for the years from 2003 through 2009 (in millions). 2003 $685 2004 786 2005 913 2006 378 2007 213 2008 163 2009 44 Above-Market Lease Costs In 1997, FirstEnergy was formed through a merger between OE and Centerior Energy Corporation. 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, in 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above March 1 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 March 1 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 March 1 market lease liability 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 under the transition plan. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $37 million per year). 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 No.SFAS) 142, "Goodwill and Other Intangible Assets". The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $48 million per year). Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. 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. FirstEnergy has reflected the net impact of the accounting for these items for the period from the merger in 1997 through 2001 in the 2002 financial statements. The cumulative impact to net income recorded in 2002 related to these prior periods increased net income by $5.9 million in the restated 2002 financial statements and is reflected as a reduction in other operating expenses in the accompanying consolidated statement of income. In addition, the impact increased the following balances in the consolidated balance sheet as of January 1, 2002: 6
INCREASE (DECREASE) (IN THOUSANDS) Goodwill............................ $ 381,780 Regulatory assets................... 636,100 ---------- Total assets........................ $1,017,880 ========== Other current liabilities........... 84,600 Deferred income taxes............... (262,580) Deferred investment tax credits..... (828) Other deferred credits.............. 1,190,800 ---------- Total liabilities................... $1,011,992 ========== Retained earnings................... $ 5,888 ==========
The after-tax effect of the actual 2002 impact of these items decreased net income for the year ended December 31, 2002, by $71 million, or $0.24 per share. The effects of these changes on the Consolidated Statement of Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows previously reported for December 31, 2002 are described in Note 2(M) to the Consolidated Financial Statements. The adjustments described above are anticipated to result in a decrease in reported net income through 2005 and an increase in net income for the period 2006 through 2017, the end of the lease term for Beaver Valley Unit 2. The schedule below shows the estimated impact on net income of these adjustments for 2003 through 2008.
CHANGE IN REGULATORY LEASE EFFECT ON EFFECT TRANSITION COST ASSET LIABILITY PRE-TAX ON NET YEAR AMORTIZATION AMORTIZATION (A) REVERSAL INCOME INCOME ---- ------------ ---------------- -------- ------ ------ (in millions) 2003 $(68) $(103) $85 $(86) $(51) 2004 (40) (118) 85 (73) (43) 2005 36 (136) 85 (16) (9) 2006 33 (83) 85 35 20 2007 64 (77) 85 72 43 2008 106 (56) 85 135 80
(a) This represents the additional amortization related to the regulatory assets recognized in connection with the above-market lease for the Bruce Mansfield Plant discussed above. Other Adjustments - FirstEnergy has also included in this restatement certain immaterial adjustments that were not previously recognized in 2002 related to the recognition of a valuation allowance on a tax benefit recognized in 2002 and other adjustments. The impact of these adjustments decreased net income by $11.3 million. The total after-tax effect of the adjustments in this restatement decreased net income for the year ended December 31, 2002, by $76 million, or $0.26 per share as shown below.
INCOME STATEMENT EFFECTS ------------------------ INCREASE (DECREASE) TRANSITION REVERSAL COST OF LEASE TOTAL AMORTIZATION OBLIGATIONS OTHER ADJUSTMENTS ------------ ----------- -------- ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Total revenues ............................ $ -- $ -- $ -- $ -- Fuel and purchased power .................. -- -- (10,700) (10,700) Other operating expenses .................. -- (90,688) 14,800 75,888 Provision for depreciation and amortization 150,474 50,272 -- 200,746 ------------ ----------- -------- ----------- Income before interest and income taxes ... 150,474 40,416 (4,100) 114,158 Net interest charges ...................... -- -- (3,300) (3,300) Income taxes .............................. (30,920) (13,962) 10,500 (34,382) ------------ ----------- -------- ----------- Net income effect ......................... $ 119,554 $ 54,378 $(11,300) $ 76,476 ============ =========== ======== =========== Basic earnings per share effect ........... $ (0.42) $ 0.20 $ (0.04) $ (0.26) ============ =========== ======== =========== Diluted earnings per share effect $ (0.42) $ 0.20 $ (0.04) $ (0.26) ============ =========== ======== ===========
7 GPU MERGER On November 7, 2001, the merger of FirstEnergy and GPU became effective with FirstEnergy being the surviving company. The merger was accounted for using purchase accounting under the guidelines of SFAS 141, "Business Combinations." Under purchase accounting, the results of operations for the combined entity are reported from the point of consummation forward. As a result, our financial statements for 2001 reflect twelve months of operations for our pre-merger organization and seven weeks of operations (November 7, 2001 to December 31, 2001) for the former GPU companies. In 2002, our financial statements include twelve months of operations for both our pre-merger organization and the former GPU companies. Additional goodwill resulting from the merger ($2.3 billion) plus goodwill existing at GPU ($1.9 billion) at the time of the merger is not being amortized, reflecting the application of SFAS 142, "Goodwill and Other Intangible Assets." Goodwill continues to be subject to review for potential impairment (see Significant Accounting Policies - Goodwill). As a result of the merger, we issued nearly 73.7 million shares of our common stock, which are reflected in the calculation of earnings per share of common stock in 2002 and for the seven-week period outstanding in 2001. RESULTS OF OPERATIONS Net income decreased to $552.8 million in 2002, compared to $646.4 million in 2001 and $599.0 million in 2000. Net income in 2001 included the cumulative effect of an accounting change resulting in a net after-tax charge of $8.5 million (see Cumulative Effect of Accounting Changes). Excluding the former GPU companies' results (and related interest expense on acquisition debt), net income decreased to $404.2 million in 2002 from $615.5 million in 2001 due in large part to the incremental costs related to the extended Davis-Besse outage and a number of one-time charges summarized in the table below. In addition, SFAS 142, implemented January 1, 2002, resulted in the cessation of goodwill amortization. In 2001, amortization of goodwill reduced net income by approximately $57 million ($0.25 per share of common stock). Excluding the former GPU companies' results (and related interest expense on acquisition debt), net income increased in 2001 due to reduced depreciation and amortization, general taxes and net interest charges. The benefits of these reductions were offset in part by lower retail electric sales, increased other operating expenses and higher gas costs. Incremental costs related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) reduced basic and diluted earnings per share of common stock by $0.47 in 2002. In addition, the table below displays one-time charges that resulted in a comparative net reduction to basic and diluted earnings of $0.46 per share of common stock in 2002, compared to 2001. Previously reported variances of revenues, expenses, income taxes and net income between 2001 as compared to 2000 included in Results of Operations - Business Segments have been reclassified as a result of segment information reclassifications (see Note 8 for additional discussion). In addition, previously reported comparisons of sales of electricity between 2001 as compared to 2000 have also been reclassified as a result of adoption of Emerging Issues Task Force (EITF) 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" (see Implementation of Recent Accounting Standard for additional disclosure). The impact of domestic and world economic conditions on the electric power industry limited our divestiture program during 2002. By the end of 2001, we had successfully completed the sale of our Australian gas transmission companies, had reached agreement with Aquila, Inc. for the sale of our holdings of electric distribution facilities in the United Kingdom (UK) and executed an agreement with NRG Energy Inc. (NRG) for the sale of four coal-fired power plants. However, the UK transaction with Aquila 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 Energy Partners Holdings (Avon) for approximately $1.9 billion (including the assumption of $1.7 billion of debt). In the fourth quarter of 2002, we recognized a $50 million impairment of our Avon investment. On August 8, 2002, we notified NRG that we were canceling our agreement with them for their purchase of the four fossil plants because NRG had stated that it could not complete the transaction under the original terms of the agreement. We were also actively pursuing the sale of an electric distribution company in Argentina - GPU Empressa Distribuidora Electrica Regional S.A. and its affiliates (Emdersa). With the deteriorating economic conditions in Argentina no sale could be completed by December 31, 2002. (See Note 3 regarding the April 2003 abandonment). Further information on the impact of the changes in accounting related to our divestiture activities is available in the "Change in Previously Reported Income Statement Classifications" section and in the discussion of depreciation charges in the "Expenses" section below. One-time pre-tax charges to earnings before the cumulative effect of accounting change are summarized in the following table: 8 ONE-TIME CHARGES
2002 2001 CHANGE ------ ------ ------ (IN MILLIONS) Investment impairments................................... $100.7 -- $100.7 Pennsylvania deferred energy costs....................... 55.8 -- 55.8 Avon and Emdersa adjustment.............................. 61.0 -- 43.5 Lake Plants - depreciation and sale costs................ 29.2 -- 29.2 Long-term derivative contract adjustment................. 18.1 -- 18.1 Generation project cancellation.......................... 17.1 -- 17.1 Severance costs - 2002................................... 11.3 -- 11.3 Uncollectible reserve and contract losses................ -- 9.2 (9.2) Early retirement costs - 2001............................ -- 8.8 (8.8) Estimated claim settlement............................... 16.8 -- 16.8 ------ ------ ------ ......................................................... $310.0 $ 18.0 $274.5 ====== ====== ====== REDUCTION TO EARNINGS PER SHARE OF COMMON STOCK BASIC.................................................. $ 0.76 $ 0.05 $0.65 ====== ====== ====== DILUTED................................................ $ 0.76 $ 0.05 $0.65 ====== ====== ======
Revenues Total revenues increased $4.2 billion in 2002, which included more than $4.6 billion incremental revenues for the former GPU companies in 2002 (twelve months), compared to 2001 (seven weeks). Excluding results from the former GPU companies, total revenues increased $24.7 million following a $336.7 million increase in 2001. The additional sales in both years resulted from an expansion of our unregulated businesses, which more than offset lower sales from our electric utility operating companies (EUOC). Sources of changes in pre-merger and post-merger companies' revenues during 2002 and 2001, compared to the prior year, are summarized in the following table: 9
SOURCES OF REVENUE CHANGES 2002 2001 -------------------------- -------- -------- INCREASE (DECREASE) (IN MILLIONS) Pre-Merger Companies: Electric Utilities (Regulated Services): Retail electric sales .............................. $ (328.5) $ (240.5) Other revenues ..................................... 18.4 (22.6) -------- -------- Total Electric Utilities ............................. (310.1) (263.1) -------- -------- Unregulated Businesses (Competitive Services): Retail electric sales .............................. 136.4 (19.9) Wholesale electric sales: Nonaffiliated .................................... 140.0 254.4 Affiliated ....................................... 345.3 32.7 Gas sales .......................................... (171.7) 226.1 Other revenues ..................................... (115.2) 106.5 -------- -------- Total Unregulated Businesses ......................... 334.8 599.8 -------- -------- Total Pre-Merger Companies ........................... 24.7 336.7 -------- -------- Former GPU Companies: Electric utilities ................................. 3,782.4 570.4 Unregulated businesses ............................. 766.0 101.9 -------- -------- Total Former GPU Companies ........................... 4,548.4 672.3 Intercompany Revenues ................................ (341.9) (38.6) -------- -------- Net Revenue Increase ................................. $4,231.2 $ 970.4 ======== ========
Electric Sales Shopping by Ohio customers for alternative energy suppliers combined with the effect of a sluggish national economy on regional business reduced retail electric sales revenues of our pre-merger EUOCs by $328.5 million (or 7.1%) in 2002 compared to 2001. Since Ohio opened its retail electric market to competing generation suppliers in 2001, sales of electric generation by alternative suppliers in our franchise areas have risen steadily, providing 23.6% of total energy delivered to retail customers in 2002, compared to 11.3% in 2001. As a result, generation kilowatt-hour sales to retail customers by the EUOC were 14.2% lower in 2002 than the prior year, which reduced regulated retail electric sales revenues by $230.6 million. Revenue from distribution deliveries decreased by $11.7 million in 2002 compared to 2001. KWH deliveries to franchise customers were 0.5% lower in 2002 compared to the prior year. The decrease resulted from the net effect of a 6.3% increase in kilowatt-hour deliveries to residential customers (due in large part to warmer summer weather in 2002) offset by a 3.2% decline in kilowatt-hour deliveries to commercial and industrial customers as a result of sluggish economic conditions. The remaining decrease in regulated retail electric sales revenues resulted from additional transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $86.0 million of additional credits in 2002 compared to 2001. These reductions to revenue are deferred for future recovery under our Ohio transition plan and do not materially affect current period earnings. Despite the decrease in kilowatt-hour sales by our pre-merger EUOC, total electric generation sales increased by 22.0% in 2002 compared to the prior year as a result of higher kilowatt-hour sales by our competitive services segment. Revenues from the wholesale market increased $501.4 million in 2002 from 2001 and kilowatt-hour sales more than doubled. More than half of the increase resulted from additional affiliated company sales by FES to Met-Ed and Penelec. FES assumed the supply obligation in the third quarter of 2002 for a portion of Met-Ed's and Penelec's provider of last resort (PLR) supply requirements (see State Regulatory Matters - Pennsylvania). The increase also included sales into the New Jersey market as an alternative supplier for a portion of New Jersey's basic generation service (BGS). Retail sales by our competitive services segment increased by $136.4 million as a result of a 59.0% increase in kilowatt-hour sales in 2002 from 2001. That increase resulted from retail customers switching to FES, our unregulated subsidiary, 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. In 2001, our pre-merger EUOC retail revenues decreased by $240.5 million compared to 2000, principally due to lower generation sales volume resulting from the first year of customer choice in Ohio. Sales by alternative suppliers increased to 11.3% of total energy delivered compared to 0.8% in 2000. Implementation of a 5% reduction in generation 10 charges for residential customers as part of Ohio's electric utility restructuring in 2001 also contributed $51.2 million to the reduced electric sales revenues. Kilowatt-hour deliveries to franchise customers were down a more moderate 1.7% due in part to the decline in economic conditions, which was a major factor resulting in a 3.1% decrease in kilowatt-hour deliveries to commercial and industrial customers. Other regulated electric revenues decreased by $22.6 million in 2001, compared to the prior year, due in part to reduced customer reservation of transmission capacity. Total electric generation sales increased by 2.7% in 2001 compared to the prior year with sales to the wholesale market being the largest single factor contributing to this increase. Kilowatt-hour sales to wholesale customers more than doubled from 2000 and revenues increased $287.1 million in 2001 from the prior year. The higher kilowatt-hour sales benefited from increased availability of power to sell into the wholesale market, due to additional internal generation and increased shopping by retail customers from alternative suppliers, which allowed us to take advantage of wholesale market opportunities. Retail kilowatt-hour sales by our competitive services segment increased by 3.6% in 2001, compared to 2000, primarily due to expanding sales within Ohio as a result of retail customers switching to FES under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio were partially offset by lower sales in markets outside of Ohio as some customers returned to their local distribution companies. Despite an increase in kilowatt-hour sales in Ohio's competitive market, declining sales to higher-priced eastern markets contributed to an overall decline in retail competitive sales revenue in 2001 from the prior year. Changes in electric generation sales and distribution deliveries in 2002 and 2001 for our pre-merger companies are summarized in the following table:
CHANGES IN KWH SALES 2002 2001 -------------------- ------ ------ INCREASE (DECREASE) Electric Generation Sales: Retail - Regulated services ................................ (14.2)% (12.2)% Competitive services .............................. 59.0% 3.6% Wholesale ........................................... 122.6% 117.2% ------ ------ Total Electric Generation Sales ...................... 22.0% 2.7% ====== ====== EUOC Distribution Deliveries: Residential ......................................... 6.3% 1.7% Commercial and industrial ........................... (3.2)% (3.1)% ------ ------ Total Distribution Deliveries ........................ (0.5)% (1.7)% ====== ======
Our regulated and unregulated subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with Emerging Issues Task Force (EITF) Issue No. 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. 11 The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows:
2002 2001 2000 ---- ---- ---- (IN MILLIONS) Sales $453 $142 $315 Purchases 687 204 271 ---- ---- ----
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 we 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 we required additional power to meet our retail load requirements and, secondarily, to sell in the wholesale market. Nonelectric Sales Nonelectric sales revenues declined by $284.6 million in 2002 from 2001. The elimination of coal trading activities in the second half of 2001 and reduced natural gas sales were the primary factors contributing to the lower revenues. Reduced gas revenues resulted principally from lower prices compared to 2001. Despite a slight reduction in sales volume and lower prices in 2002, margins from gas sales improved (see Expenses below). Reduced revenues from the facilities services group also contributed to the decrease in other sales revenue in 2002, compared to 2001. In 2001, nonelectric revenues increased $332.6 million, with natural gas revenues providing the largest source of increase. Beginning November 1, 2000, residential and small business customers in the service area of a nonaffiliated gas utility began shopping among alternative gas suppliers as part of a customer choice program. FES's ability to take advantage of this opportunity to expand its customer base contributed to the increase in natural gas revenues. Expenses Total expenses increased nearly $3.8 billion in 2002, which included more than $3.7 billion of incremental expenses for the former GPU companies in 2002 (twelve months), compared to 2001 (seven weeks). For our pre-merger companies, total expenses increased $409.9 million in 2002 and $280.4 million in 2001, compared to the respective prior years. Sources of changes in pre-merger and post-merger companies' expenses in 2002 and 2001, compared to the prior year, are summarized in the following table:
SOURCES OF EXPENSE CHANGES 2002 2001 ------------------------------- -------- -------- INCREASE (DECREASE) (IN MILLIONS) PRE-MERGER COMPANIES: Fuel and purchased power $ 431.0 $ 48.7 Purchased gas (227.9) 266.5 Other operating expenses 102.6 178.2 Depreciation and amortization 75.6 (99.0) General taxes 28.5 (114.0) -------- -------- TOTAL PRE-MERGER COMPANIES 409.9 280.4 -------- -------- FORMER GPU COMPANIES 3,730.0 542.4 INTERCOMPANY EXPENSES (353.9) (32.6) -------- -------- NET EXPENSE INCREASE $3,785.9 $ 790.2 ======== ========
The following comparisons reflect variances for the pre-merger companies only, excluding the incremental expenses for the former GPU companies in 2002 and 2001. Higher fuel and purchased power costs in 2002 compared to 2001 primarily reflect additional purchased power costs of $352.9 million. The increase resulted from additional volumes to cover supply obligations assumed by FES. These included a portion of Met-Ed's and Penelec's PLR supply requirements (which started in the third quarter of 2002), contract sales including 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). Fuel expense increased $99.5 million in 2002 from the prior year principally due to additional internal generation (5.4% higher) and an increased mix of coal and natural gas generation in 2002. The extended outage at the Davis-Besse nuclear plant produced a decline in nuclear generation of 14.6% in 2002, compared to 2001. Purchased gas costs decreased by $227.9 million primarily due to lower unit costs of natural gas purchased in 2002 compared to the prior year resulting in a $48.4 million improvement in gas margins. 12 In 2001, the increase in fuel expense compared to 2000 ($24.3 million) resulted from the substitution of coal and natural gas fired generation for nuclear generation during a period of reduced nuclear availability resulting from both planned and unplanned outages. Higher unit costs for coal consumed also contributed to the increase during that period. Purchased power costs increased early in 2001, compared to 2000, due to higher winter prices and additional purchased power requirements during that period, with the balance of the year offsetting all but $24.4 million of that increase as a result of generally lower prices and reduced external power needs compared to 2000. Purchased gas costs increased 48% in 2001 compared to 2000, principally due to the expansion of FES's retail gas business. Other operating expenses increased $102.6 million in 2002 from the previous year. The increase principally resulted from several large offsetting factors. Nuclear costs increased $125.3 million primarily due to $115.0 million of incremental Davis-Besse costs related to its extended outage (see Davis-Besse Restoration). One-time charges, discussed above, added $98.3 million and an aggregate increase in administrative and general expenses and non-operating costs of $127.4 million resulted in large part from higher employee benefit expenses. Partially offsetting these higher costs were the elimination in the second half of 2001 of coal trading activities ($95.4 million) and reduced facilities service business ($58.9 million). The reversal of lease obligations related to the Bruce Mansfield fossil facility and Beaver Valley nuclear facility reduced other operating expenses by $84.8 million in 2002 as compared to 2001. In 2001, other operating expenses increased by $178.2 million compared to the prior year. The significant reduction in 2001 of gains from the sale of emission allowances, higher fossil operating costs and additional employee benefit costs accounted for $144.5 million of the increase in 2001. Additionally, higher operating costs from the competitive services business segment due to expanded operations contributed $56.9 million to the increase. Partially offsetting these higher other operating expenses was a reduction in low-income payment plan customer costs and a $30.2 million decrease in nuclear operating costs in 2001, compared to 2000, resulting from one less refueling outage. Fossil operating costs increased $44.3 million in 2001 from 2000 due principally to planned maintenance work at the Bruce Mansfield generating plant. Pension costs increased by $32.6 million in 2001 from 2000 primarily due to lower returns on pension plan assets (due to significant market-related reductions in the value of pension plan assets), the completion of the 15-year amortization of OE's pension transition asset and changes to plan benefits. Health care benefit costs also increased by $21.4 million in 2001, compared to 2000, principally due to an increase in the health care cost trend rate assumption for computing post-retirement health care benefit liabilities. Charges for depreciation and amortization increased $75.6 million in 2002 from the preceding year. This increase resulted from several factors: increased amortization under the Ohio transition plan ($201 million). The start up of a new fluidized bed boiler in January 2002, owned by Bayshore Power Company, a wholly owned subsidiary, resulted in higher depreciation expense in 2002. Also, new combustion turbine capacity added in late 2001 and two months of 2001 depreciation recorded in 2002 (for the four fossil plants we chose not to sell) increased depreciation expense in 2002. However, two factors offset a portion of the above increase: shopping incentive deferrals and tax-deferrals under the Ohio transition plan ($108.5 million) and the cessation of goodwill amortization ($56.4 million) beginning January 1, 2002. In 2001, charges for depreciation and amortization decreased by $99.0 million from the prior year. Approximately $64.6 million of the decrease resulted from lower incremental transition cost amortization under our Ohio transition plan compared to accelerated cost recovery in connection with OE's prior rate plan. The reduction in depreciation and amortization also reflected additional cost deferrals of $51.2 million for recoverable shopping incentives under the Ohio transition plan, partially offset by increases associated with depreciation on completed combustion turbines in the fourth quarter of 2001. General taxes increased $28.5 million in 2002 from 2001 principally due to additional property taxes and the absence in 2002 of a one-time benefit of $15 million resulting from the successful resolution of certain property tax issues in the prior year. In 2001, general taxes declined $114.0 million from 2000 primarily due to reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring. The reduction in general taxes was partially offset by $66.6 million of new Ohio franchise taxes, which are classified as state income taxes on the Consolidated Statements of Income. Net Interest Charges Net interest charges increased $406.6 million in 2002, compared to 2001. These increases included interest on $4 billion of long-term debt issued by FirstEnergy in connection with the merger. Excluding the results associated with the former GPU companies and merger-related financing, net interest charges decreased $57.0 million in 2002, compared to a $39.8 million decrease in 2001 from 2000. Our continued redemption and refinancing of our outstanding debt and preferred stock during 2002, maintained our downward trend in financing costs, before the effects of the GPU merger. Excluding activities related to the former GPU companies, redemption and refinancing activities for 2002 totaled $1.1 billion and $143.4 million, respectively, and are expected to result in annualized savings of $86.0 million. We also exchanged existing fixed-rate payments on outstanding debt (principal amount of $593.5 million at year end 2002) for 13 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 $17.4 million in 2002 as a result of these swaps. Discontinued Operations In April 2003, FirstEnergy divested its ownership in GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) through the abandonment of its shares in the parent company of the Argentina operation. FirstEnergy has reclassified the results of Emdersa for the year ended December 31, 2002, totaling $87.5 million in discontinued operations. Cumulative Effect of Accounting Change In 2001, we adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" resulting in an $8.5 million after-tax charge. (See Note 2J) Postretirement Plans Sharp declines in equity markets since the second quarter of 2000 and a reduction in our assumed discount rate in 2001 have combined to produce a negative trend in pension expenses - moving from a net increase to earnings in 2000 and 2001 to a reduction of earnings in 2002. Also, increases in health care payments and a related increase in projected trend rates have led to higher health care costs. The following table presents the pre-tax pension and other post-employment benefits (OPEB) expenses for our pre-merger companies (excluding amounts capitalized):
POSTRETIREMENT EXPENSES (INCOME) 2002 2001 2000 -------------------------------- ------ ------ ------ (IN MILLIONS) Pension $ 16.4 $(11.1) $(40.6) OPEB 99.1 86.6 65.5 ------ ------ ------ Total $115.5 $ 75.5 $ 24.9 ====== ====== ======
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 and anticipated pension and OPEB expense increases in 2003. RESULTS OF OPERATIONS - BUSINESS SEGMENTS We manage our business as two separate major business segments - regulated services and competitive services. The regulated services segment designs, constructs, operates and maintains our regulated domestic transmission and distribution systems. It also provides generation services to franchise customers who have not chosen an alternative generation supplier. OE, CEI and TE (Ohio Companies) and Penn obtain generation through a power supply agreement with the competitive services segment (see Outlook - Business Organization). 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 application services. Competitive products are increasingly marketed to customers as bundled services, often under master contracts. Financial results discussed below include intersegment revenue. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Financial data for 2002 and 2001 for the major business segments include reclassifications to conform with the current business segment organizations and operations, which affect 2002 and 2001 results discussed below. Regulated Services Net income increased to $938 million in 2002, compared to $729.1 million in 2001 and $562.5 million in 2000. Excluding additional net income of $312.7 million associated with the former GPU companies, net income decreased by $103.7 million in 2002. The changes in pre-merger net income are summarized in the following table:
REGULATED SERVICES 2002 2001 ------------------ ------- ------- INCREASE (DECREASE) (IN MILLIONS) Revenues $(529.5) $(116.4) Expenses (232.4) (344.1) ------- ------- Income Before Interest and Income Taxes (297.1) 227.7 ------- ------- Net interest charges (131.3) (16.8) Income taxes (62.1) 132.7 ------- ------- Net Income Change $(103.7) $ 111.8 ======= =======
Lower generation sales, additional transition plan incentives and a slight decline in revenue from distribution deliveries combined for a $312.5 million reduction in external revenues in 2002 from the prior year. Shopping by Ohio customers from alternative energy suppliers combined with the effect of a sluggish national economy on our regional 14 business reduced retail electric sales revenues. In addition, a $188.0 million decline in revenues resulted from reduced sales to FES, due to the extended outage of the Davis-Besse nuclear plant, which reduced generation available for sale. The $232.4 million decrease in expenses primarily resulted from three major factors: a $190.5 million decrease in purchased power, a $111.6 million reduction in other operating expenses and a $58.9 million increase in depreciation expense. Lower generation sales reduced the need for purchased power and other operating expenses reflected reduced costs in jobbing and contracting work and decreased uncollectible accounts expense. Higher depreciation and amortization resulted from $201 million higher incremental transition costs partially offset by $108.5 million of new deferred regulatory assets under the Ohio transition plan and the cessation of goodwill amortization beginning January 1, 2002. In 2001, distribution throughput was 1.7% lower, compared to 2000, reducing external revenues by $245.7 million. Partially offsetting the decrease in external revenues were revenues from FES for the rental of fossil generating facilities and the sale of generation from nuclear plants, resulting in a net $116.4 million reduction to total revenues. Expenses were $344.1 million lower in 2001 than 2000 due to lower purchased power, depreciation and amortization and general taxes, offset in part by higher other operating expenses. Lower generation sales reduced the need to purchase power from FES, with a resulting $267.8 million decline in those costs in 2001 from the prior year. Other operating expenses increased by $178.5 million in 2001 from the previous year reflecting a significant reduction in 2001 of gains from the sale of emission allowances, higher fossil operating costs and additional employee benefit costs. Lower incremental transition cost amortization and the new shopping incentive deferrals under our Ohio transition plan as compared with the accelerated cost recovery in connection with OE's prior rate plan in 2000 resulted in a $131.0 million reduction in depreciation and amortization in 2001. A $123.6 million decrease in general taxes in 2001 from the prior year primarily resulted from reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring. Competitive Services Net losses increased to $119.0 million in 2002, compared to $31.8 million in 2001 and net income of $39.1 million in 2000. Excluding additional net income of $2.6 million associated with the former GPU companies, net losses increased by $89.8 million in 2002. The changes to pre-merger earnings are summarized in the following table:
COMPETITIVE SERVICES 2002 2001 -------------------- ------ ------ INCREASE (DECREASE) (IN MILLIONS) Revenues $211.5 $289.3 Expenses 351.1 392.5 ------ ------ Income Before Interest and Income Taxes (139.6) (103.2) ------ ------ Net interest charges 21.9 13.5 Income taxes (63.2) (51.3) Cumulative effect of a change in accounting 8.5 (8.5) ------ ------ Net Loss Increase $ 89.8 $ 73.9 ====== ======
The $211.5 million increase in revenues in 2002, compared to 2001, represents the net effect of several factors. Revenues from the wholesale electricity market increased $485.3 million in 2002 from the prior year and KWH sales more than doubled. More than half of the increase resulted from additional sales to Met-Ed and Penelec to supply a portion of their PLR supply requirements in Pennsylvania, as well as BGS sales in New Jersey and sales under several other contracts. Retail KWH sales revenues increased $136.4 million as a result of expanding KWH sales within Ohio under Ohio's electricity choice program. Total electric sales revenue increased $621.7 million in 2002 from 2001, accounting for almost all of the net increase in revenues. Offsetting the higher electric sales revenue were reduced natural gas revenues ($171.7 million) primarily due to lower prices and less revenue from FSG ($65.5 million) reflecting the sluggish economy. Internal sales to the regulated services segment decreased $179.8 million in large part due to the impact of customer shopping reducing requirements by the regulated services segment. Expenses increased $351.1 million in 2002 from the prior year, due to additional purchased power ($342.2 million) to supply the incremental KWH sales to wholesale and retail customers. Other operating expenses increased $207.2 million from the prior year as a result of higher nuclear costs due to incremental Davis-Besse costs from its extended outage. One-time charges discussed above increased costs by $75.6 million. Offsetting these increases were reduced purchased gas costs ($227.9 million) primarily resulting from lower prices and reduced costs from FSG reflecting reduced business activity. In 2001, sales to nonaffiliates increased $523.2 million, compared to the prior year, with electric revenues contributing $299.8 million, natural gas revenues adding $226.1 million and the balance of the change from energy-related services. Reduced power requirements by the regulated services segment reduced internal revenues by $267.8 million. Expenses increased $392.5 million in 2002 from 2001 primarily due to a $266.5 million increase in purchased gas costs and increases resulting from additional fuel and purchased power costs (see Results of Operations above) as well 15 as higher expenses for energy-related services. Reduced margins for both major competitive product areas - electricity and natural gas - contributed to the reduction in net income, along with higher interest charges and the cumulative effect of the SFAS 133 accounting change. Margins for electricity and gas sales were both adversely affected by higher fuel costs. CAPITAL RESOURCES AND LIQUIDITY 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, which it can draw upon. In 2002, FirstEnergy received $447 million of cash dividends on common stock from its subsidiaries and paid $440 million in cash dividends on common stock to its shareholders. There are no material restrictions on the issuance of cash dividends by FirstEnergy's subsidiaries. As of December 31, 2002, we had $196.3 million of cash and cash equivalents (including $50 million that redeemed long-term debt in January 2003) on our Consolidated Balance Sheet. This compares to $220.2 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided by our regulated and competitive energy services businesses (see Results of Operations - Business Segments above). Net cash flows from operating activities in 2002 reflect twelve months of cash flows for the former GPU companies while 2001 includes only seven weeks of those companies' operations (November 7, 2001 to December 31, 2001). Both periods include a full twelve months for the pre-merger companies. Net cash provided from operating activities was $1.915 billion in 2002 and $1.282 billion in 2001. The modest contribution to operating cash flows in 2002 by the former GPU companies reflects in part the deferrals of purchased power costs related to their PLR obligations (see State Regulatory Matters - New Jersey and Pennsylvania below). Cash flows provided from 2002 operating activities of our pre-merger companies and former GPU companies are as follows:
OPERATING CASH FLOWS 2002 2001 --------------------------- ------- ------- (IN MILLIONS) Pre-merger Companies: Cash earnings (1) $ 1,059 $ 1,551 Working capital and other 405 21 ------- ------- Total pre-merger companies 1,464 1,572 Former GPU companies 563 166 Eliminations (112) (456) ------- ------- Total $ 1,915 $ 1,282 ======= =======
(1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash charges. Excluding the former GPU companies, cash flows from operating activities totaled $1.464 billion in 2002 primarily due to cash earnings and to a lesser extent working capital and other changes. In 2001, cash flows from operating activities totaled $1.572 billion principally due to cash earnings. Cash Flows From Financing Activities In 2002, the net cash used for financing activities of $1.123 billion primarily reflects the redemptions of debt and preferred stock shown below. In 2001, net cash provided from financing activities totaled $1.964 billion, primarily due to $4 billion of long-term debt issued in connection with the GPU acquisition, which was partially offset by $2.1 billion of redemptions and refinancings. The following table provides details regarding new issues and redemptions during 2002: 16
SECURITIES ISSUED OR REDEEMED 2002 ----------------------------- ------- (IN MILLIONS) New Issues Pollution Control Notes $ 143 Transition Bonds (See Note 5H) 320 Unsecured Notes 210 Other, principally debt discounts (4) ------- $ 669 Redemptions First Mortgage Bonds $ 728 Pollution Control Notes 93 Secured Notes 278 Unsecured Notes 189 Preferred Stock 522 Other, principally redemption premiums 21 ------- $1,831 Short-term Borrowings, Net $ 479 -------
We had approximately $1.093 billion of short-term indebtedness at the end of 2002 compared to $614.3 million at the end of 2001. Available borrowing capability included $177 million under the $1.5 billion revolving lines of credit and $64 million under bilateral bank facilities. At the end of 2002, OE, CEI, TE and Penn had the aggregate capability to issue $2.1 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. JCP&L, Met-Ed and Penelec will 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 December 31, 2002, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $474 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 $4.3 billion of preferred stock (assuming no additional debt was issued) as of the end of 2002. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock (see Note 5G - Long-Term Debt for discussion of debt covenants). At the end of 2002, our common equity as a percentage of capitalization stood at 38% compared to 35% and 42% at the end of 2001 and 2000, respectively. The lower common equity percentage in 2002 compared to 2000 resulted from the effect of the GPU acquisition. The increase in the 2002 equity percentage from 2001 primarily reflects net redemptions of preferred stock and long-term debt, financed in part by short-term borrowings, and the increase in retained earnings. Cash Flows From Investing Activities Net cash flows used in investing activities totaled $816 million in 2002. The net cash used for investing principally resulted from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Expenditures for property additions by the competitive services segment are principally generation-related including capital additions at the Davis-Besse nuclear plant during its extended outage. The following table summarizes 2002 investments by our regulated services and competitive services segments:
SUMMARY OF 2002 CASH FLOWS PROPERTY USED FOR INVESTING ACTIVITIES ADDITIONS INVESTMENTS OTHER TOTAL ----------------------------- --------- ----------- ----- ----- SOURCES (USES) (IN MILLIONS) Regulated Services $ (490) $ 87 $ (21) $(424) Competitive Services (403) -- 10 (393) Other (105) 149* (54) (10) Eliminations -- -- 11 11 --------- ----------- ----- ----- Total $ (998) $ 236 $ (54) $(816) ========= =========== ===== =====
* Includes $155 million of cash proceeds from the sale of Avon (see Note 3). In 2001, net cash flows used in investing activities totaled $3.075 billion, principally due to the GPU acquisition ($2.013 billion) and property additions ($852 million). Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets. 17
LESS THAN 1-3 3-5 MORE THAN CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR YEARS YEARS 5 YEARS ----------------------- ------- ------- ------- ------- ------- (IN MILLIONS) Long-term debt $12,465 $ 1,073 $ 2,210 $ 1,654 $ 7,528 Short-term borrowings 1,093 1,093 -- -- -- Preferred stock (1) 445 2 4 14 425 Capital leases (2) 31 5 11 7 8 Operating leases (2) 2,697 153 365 349 1,830 Purchases (3) 13,156 2,149 2,902 2,634 5,471 ------- ------- ------- ------- ------- Total $29,887 $ 4,475 $ 5,492 $ 4,658 $15,262 ======= ======= ======= ======= =======
(1) Subject to mandatory redemption (2) See Note 4 (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing Our capital spending for the period 2003-2007 is expected to be about $3.1 billion (excluding nuclear fuel), of which approximately $727 million applies to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $485 million, of which about $69 million applies to 2003. During the same period, our nuclear fuel investments are expected to be reduced by approximately $483 million and $88 million, respectively, as the nuclear fuel is consumed. In May 2002, we sold a 79.9 percent equity interest in Avon, our former wholly owned holding company of Midlands Electricity plc, to Aquila, Inc. (formerly UtiliCorp United) for approximately $1.9 billion (including assumption of $1.7 billion of debt). We received approximately $155 million in cash proceeds and approximately $87 million of long-term notes (representing the present value of $19 million per year to be received over six years beginning in 2003). In the fourth quarter of 2002, we recorded a $50 million charge to reduce the carrying value of our remaining Avon 20.1 percent equity investment. On August 8, 2002, we notified NRG that we were canceling a November 2001 agreement to sell four fossil plants for approximately $1.5 billion ($1.355 billion in cash and $145 million in debt assumption) to NRG because NRG had stated it could not complete the transaction under the original terms of the agreement. In December 2002, we announced that we would retain ownership of the plants after reviewing subsequent bids from other potential buyers. As a result of this decision, we recorded an aggregate charge of $74 million ($43 million, net of tax) in the fourth quarter of 2002, consisting of $57 million ($33 million, net of tax) in non-cash depreciation charges that were not recorded while the plants were pending sale and $17 million ($10 million, net of tax) of transaction-related fees (see Note 3). in the 2001 merger with GPU. On April 18, 2003, we divested our ownership interest in Emdersa, our Argentina operations, resulting in a charge of $87.5 million in the restated year ended December 31, 2002 Consolidated Statement of Income as "Discontinued Operations (See Note 2M). 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." On July 25, 2003, Standard & Poor's (S&P) issued comments on FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse outage and the NJBPU decision on the JCP&L rate case. S&P noted that additional costs from the Davis-Besse outage extension, the NJBPU ruling on recovery of deferred energy costs and additional capital investments required to improve reliability in the New Jersey shore communities will adversely affect FirstEnergy's cash flow and deleveraging plans. S&P noted that it continues to assess FirstEnergy's plans to determine if projected financial measures are adequate to maintain its current rating. On August 7, 2003, S&P affirmed its "BBB" corporate credit rating for FirstEnergy. However, S&P stated that although FirstEnergy generates substantial free cash, that its strategy for reducing debt had deviated substantially from the one presented to S&P around the time of the GPU merger when the current rating was assigned. S&P further noted that their affirmation of FirstEnergy's corporate credit rating was based on the assumption that FirstEnergy would take appropriate steps quickly to maintain its investment grade ratings including the issuance of equity and possible sale of assets. Key issues being monitored by S&P included reaudit of CEI and TE by PricewaterhouseCoopers LLP, restart of Davis-Besse, FirstEnergy's liquidity position, its ability to forecast provider-of-last-resort load and the performance of its hedged portfolio, and capture of merger synergies. 18 OTHER OBLIGATIONS Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected in the operating lease payments disclosed above (see Note 4). The present value as of December 31, 2002, of these sale and leaseback operating lease commitments, net of trust investments, total $1.5 billion. CEI and TE sell substantially all of their retail customer receivables, which provided $170 million of off-balance sheet financing as of December 31, 2002 (see Note 2 - Revenues). GUARANTEES AND OTHER ASSURANCES As part of normal business activities, we enter into various agreements on behalf of our subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and rating-contingent collateralization provisions. As of December 31, 2002, the maximum potential future payments under outstanding guarantees and other assurances totaled $913 million, as summarized below:
MAXIMUM GUARANTEES AND OTHER ASSURANCES EXPOSURE ------------------------------- -------- (IN MILLIONS) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1) $ 670 Financings (2)(3) 186 -------- 856 Surety Bonds 26 Rating-Contingent Collateralization (4) 31 -------- Total Guarantees and Other Assurances $ 913 ========
(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 our letters of credit supporting subsidiary debt. (3) Issued for various terms. (4) Estimated net liability under contracts subject to rating-contingent collateralization provisions. We guarantee energy and energy-related payments of our subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. We also provide guarantees to various providers of subsidiary financings principally for the acquisition of property, plant and equipment. These agreements legally obligate us and our subsidiaries to fulfill the obligations of our subsidiaries directly involved in these energy and energy-related transactions or financings 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, our guarantee enables the counterparty's legal claim to be satisfied by our other assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by us to meet our obligations incurred in connection with financings and ongoing energy and energy-related contracts. Most of our 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. 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. MARKET RISK INFORMATION We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our 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. Commodity Price Risk 19 We are exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, we use 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 our 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 2002 is summarized in the following table: INCREASE (DECREASE) IN THE FAIR VALUE OF COMMODITY DERIVATIVE CONTRACTS
NON-HEDGE HEDGE TOTAL --------- --------- --------- (IN MILLIONS) Outstanding net asset (liability) as of January 1, 2002 $ 9.9 $ (76.3) $ (66.4) New contract value when entered -- 2.2 2.2 Additions/Increase in value of existing contracts 55.5 73.9 129.4 Change in techniques/assumptions (20.1) -- (20.1) Settled contracts 8.5 24.3 32.8 --------- --------- --------- Outstanding net asset as of December 31, 2002 (1) 53.8 24.1 77.9 --------- --------- --------- NON-COMMODITY NET ASSETS AS OF DECEMBER 31, 2002: Interest Rate Swaps (2) -- 20.5 20.5 --------- --------- --------- NET ASSETS - DERIVATIVES CONTRACTS AS OF DECEMBER 31, 2002 (3) $ 53.8 $ 44.6 $ 98.4 ========= ========= ========= Impact of Changes in Commodity Derivative Contracts (4) Income Statement Effects (Pre-Tax) $ 13.9 $ -- $ 13.9 Balance Sheet Effects: Other Comprehensive Income (OCI) (Pre-Tax) $ -- $ 98.2 $ 98.2 Regulatory Liability $ 30.0 $ -- $ 30.0
(1) Includes $34.2 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are primarily treated as fair value hedges. Changes in derivative values of the fair value hedges are offset by changes in the hedged debts' premium or discount (see Interest Rate Swap Agreements below). (3) Excludes $9.3 million of derivative contract fair value decrease, as of December 31, 2002, representing our 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 December 31, 2002:
NON-HEDGE HEDGE TOTAL --------- --------- --------- (IN MILLIONS) CURRENT- Other Assets $ 31.2 $ 14.9 $ 46.1 Other Liabilities (16.2) (8.8) (25.0) NON-CURRENT- Other Deferred Charges 39.6 39.4 79.0 Other Deferred Credits (0.8) (0.9) (1.7) --------- --------- --------- NET ASSETS $ 53.8 $ 44.6 $ 98.4 ========= ========= =========
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: 20
SOURCE OF INFORMATION - FAIR VALUE BY CONTRACT YEAR 2003 2004 2005 2006 THEREAFTER TOTAL ------------------------------- ------ ------ ------ ------ ---------- ----- (IN MILLIONS) Prices actively quoted(1) $ 16.0 $ 1.5 $ -- $ -- $ -- $17.5 Other external sources(2) 22.2 2.1 (0.9) -- -- 23.4 Prices based on models -- -- -- 5.5 31.5 37.0 ------ ------ ------ ------ ---------- ----- TOTAL(3) $ 38.2 $ 3.6 $ (0.9) $ 5.5 $ 31.5 $77.9 ====== ====== ====== ====== ========== =====
(1) Exchange traded. (2) Broker quote sheets. (3) Includes $34.2 million from an embedded option that is offset by a regulatory liability and does not affect earnings. We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2002. We estimate that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would decrease by approximately $3.7 million. Interest Rate Risk Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below. We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 4 to the consolidated financial statements, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds had been recognized by making corresponding changes to the decommissioning liability, as described in Note 2 to the consolidated financial statements. While fluctuations in the fair value of our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers the difference between the investments held in trust and their decommissioning obligations. Thus, in absence of disallowed costs, there should be no earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2002, decommissioning trust balances totaled $1.050 billion, with $698 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of equity and 49% of debt instruments.
COMPARISON OF CARRYING VALUE TO FAIR VALUE ------------------------------------------ THERE- FAIR YEAR OF MATURITY 2003 2004 2005 2006 2007 AFTER TOTAL VALUE ---------------- ------ ------ ------ ------ ------ ------- ------- ------- (DOLLARS IN MILLIONS) Assets Investments other than Cash and Cash Equivalents-Fixed Income $ 115 $ 327 $ 72 $ 90 $ 85 $ 1,843 $ 2,532 $ 2,638 Average interest rate 7.5% 7.8% 8.1% 8.1% 8.2% 6.3% 6.8% Liabilities Long-term Debt: Fixed rate $ 964 $ 939 $ 867 $1,401 $ 252 $ 6,386 $10,809 $11,119 Average interest rate 7.7% 7.2% 8.1% 5.7% 6.7% 7.0% 7.0% Variable rate $ 109 $ 399 $ 5 $ 1 $ 1,142 $ 1,656 $ 1,642 Average interest rate 5.4% 2.6% 6.7% 6.1% 2.7% 2.9% Short-term Borrowings $1,093 $ 1,093 $ 1,093 Average interest rate 2.4% 2.4% ------ ------ ------ ------ ------ ------- ------- ------- Preferred Stock $ 2 $ 2 $ 2 $ 2 $ 12 $ 425 $ 445 $ 454 Average dividend rate 7.5% 7.5% 7.5% 7.5% 7.6% 8.1% 8.1% ------ ------ ------ ------ ------ ------- ------- -------
Interest Rate Swap Agreements During 2002, FirstEnergy entered into fixed-to-floating interest rate swap agreements, to increase the variable-rate component of its debt portfolio from 16% to approximately 20% at year end. 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. During the fourth quarter of 2002, in a period of steadily declining market interest rates, we unwound swaps with a total notional amount of $400 million that we had entered into during the second and third quarters of 2002. Under fair-value accounting, the swaps' fair value ($19.9 million asset) was added to the carrying value 21 of the hedged debt and will be amortized to maturity. Offsets to interest expense recorded in 2002 due to the difference between fixed and variable debt rates totaled $17.4 million. As of December 31, 2002, the debt underlying FirstEnergy's outstanding interest rate swaps had a weighted average fixed interest rate of 7.76%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.04%. GPU Power (through a subsidiary) used dollar-denominated interest rate swap agreements in 2002. In 2001, Penelec, GPU Power (through a subsidiary) and GPU Electric, Inc. (through GPU Power UK) used interest rate swaps denominated in dollars and sterling. All of the agreements of the former GPU companies 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% in 2002 and 6.99% in 2001. The following summarizes the principal characteristics of the swap agreements: INTEREST RATE SWAPS
DECEMBER 31, 2002 DECEMBER 31, 2001 ---------------------------- ----------------------------- NOTIONAL MATURITY FAIR NOTIONAL MATURITY FAIR DENOMINATION AMOUNT DATE VALUE AMOUNT DATE VALUE ------------ -------- -------- ----- -------- -------- ----- (DOLLARS/STERLING IN MILLIONS) Fixed to Floating Rate Dollar 444 2023 15.5 150 2025 5.9 Floating to Fixed Rate Dollar 16 2005 (0.9) 50 2002 (1.8) 26 2005 (1.1) Sterling 125 2003 (2.3) -------- -------- ----- -------- -------- -----
Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $532 million and $568 million as of December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges, would result in a $53 million reduction in fair value as of December 31, 2002 (see Note 2J - Supplemental Cash Flows Information). Foreign Currency Risk We are exposed to foreign currency risk from investments in international business operations acquired through the merger with GPU. While such risks are likely to diminish over time as we sell our international operations, we expect such risks to continue in the near term. In 2002, we experienced net foreign currency translation losses in connection with our Argentina operations (see Note 3 - Divestitures). A hypothetical 20% adverse change in our foreign currency positions in the near term would not have had a material effect on our consolidated financial position, cash flows or earnings as of December 31, 2002. OUTLOOK We continue to pursue our goal of being the leading regional supplier of energy and related services in the northeastern quadrant of the United States, where we see the best opportunities for growth. We believe that our strategy has received some measure of validation by the major industry events of 2002 and we continue to build toward a strong regional presence. We intend to provide competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to our core business. As our industry changes to a more competitive environment, we have taken and expect to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. Business Organization Beginning in 2001, Ohio utilities that offered both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the Public Utilities Commission of Ohio (PUCO) - one which provided a clear separation between regulated and competitive operations. Our business is separated into three distinct units - a competitive services segment, a regulated services segment and a corporate support segment. FES provides competitive retail energy services while the EUOC continue to 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. We expect 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. 22 Optimizing the Use of Assets 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 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 six months ended June 30, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications for the six-month 2002 period. 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. 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. 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). Midland'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 net of tax) related to the carrying value of the note FirstEnergy had with Aquila 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 its note receivable in a secondary market and received $63.2 million in proceeds on July 28, 2003. On August 8, 2002, we notified NRG that we were canceling our agreement with it for its purchase of four fossil plants because NRG had stated that it could not complete the sale transaction under the original terms of the agreement. Based on subsequent bids received, we concluded that retaining the plants to serve our customers was in the best interest of our customers and our shareholders. Following our decision to retain the four plants, we performed a comprehensive fossil operations review and subsequently decided to close the Ashtabula C-Plant (three 44 megawatt (MW), coal-fired boilers). This action is part of our strategy to provide competitively priced energy - replacing less-efficient peaking generation in our portfolio of generation resources, with the development of new, higher-efficiency peaking plants. While deteriorating economic conditions in Argentina delayed our sale of Emdersa, we continue to pursue the sale of assets that do not support our strategy in order to increase our financial flexibility by reducing debt and preferred stock. State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in our EUOC's respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of our 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. 23 Regulatory assets are costs which 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. The regulatory assets of the individual companies are as follows:
REGULATORY ASSETS AS OF DECEMBER 31, ------------------------------------ COMPANY 2002 ------- ---- (IN MILLIONS) OE $1,848.7 CEI 1,191.8 TE 578.2 Penn 156.9 JCP&L 3,199.0 Met-Ed 1,179.1 Penelec 599.7 ------------------------------------- Total $8,753.4 =====================================
Ohio FirstEnergy's transition plan (which we filed on behalf of the Ohio Companies) 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 our 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 Companies 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. Our 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). That goal was achieved in 2002. Accordingly, FirstEnergy does not believe that there will be any regulatory action reducing the recoverable transition costs. 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 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. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which reduces JCP&L's annual revenues by approximately $62 million 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 will initiate another proceeding to request recovery of additional costs 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 would be retroactive to August 1, 2003. The revenue decrease in the decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC charge. The MTC would allow for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $152.5 million. JCP&L also announced on July 25, 2003 that it is reviewing the NJBPU decision and will decide on its appropriate course of action, which could include filing an appeal for reconsideration with the NJBPU and possibly an appeal to the Appellate Division of the Superior Court of New Jersey. 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 24 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 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. 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. 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: - 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. FERC Regulatory Matters On December 19, 2002, the Federal Energy Regulatory Commission (FERC) granted unconditional Regional Transmission Organization status to PJM Interconnection, LLC which includes JCP&L, Met-Ed and Penelec as transmission owners. Also, on December 19, 2002, the FERC conditionally accepted GridAmerica's filing to become an independent transmission company within Midwest Independent System Operator, Inc. (MISO). GridAmerica will operate ATSI's transmission facilities. GridAmercia expects to begin operations in the second quarter of 2003 subject to approval of certain compliance filings with the FERC. Compliance filings were made by the GridAmerica companies (including ATSI) on January 31 and February 19, 2003. Supply Plan We are obligated to provide generation service for an estimated 2003 peak demand of 18,450 MW. These obligations arise from customers who have elected to continue to receive generation service from the EUOCs under regulated retail rate tariffs and from customers who have selected FES as their alternate generation provider. Geographically, approximately 11,000 MW of the obligations are in the East Central Area Reliability Agreement market and 7,450 MW are in the PJM ISO market area. These obligations include approximately 1,700 MW of load that FES obtained in New Jersey's BGS auction. Additionally, if alternative suppliers fail to deliver power to their customers located in the EUOCs' service areas, we could be required to serve an additional 1,400 MW as PLR. In the event we must 25 procure replacement power for an alternative supplier, the cost of that power would be recovered under the applicable state regulatory rules. To meet their obligations, our subsidiaries have 13,101 MW of installed generating capacity, 1,540 MW of long-term power purchase contracts (exceeding one year), 2,800 MW under short-term purchase contracts and approximately 800 MW of interruptible and controllable load contracts. Any additional power requirements will be satisfied through spot market purchases. All utilities in New Jersey are required to participate in an annual auction through which the entire obligation for all of their BGS requirements are auctioned to alternate suppliers. Through this auction process, the 286 MW of JCP&L's installed capacity and approximately 800 MW of long-term purchases from NUGs are made available to the winning bidders. FES participates in this annual auction as an alternate supplier and currently has an obligation to provide 1,700 MW of power for summer peak demand through July 31, 2003. 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 fall 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). The actual costs (capital and expense) associated with the extended Davis-Besse outage in 2002 and estimated costs in 2003 are:
COSTS OF DAVIS-BESSE EXTENDED OUTAGE ------------------------------------------------------------------------------------- (IN MILLIONS) 2002 - ACTUAL ------------- Capital Expenditures: Reactor head and restart $ 63.3 Incremental Expenses (pre-tax): Maintenance 115.0 Fuel and purchased power 119.5 ----- Total $234.5 ====== 2003 - ESTIMATED ---------------- Primarily operating expenses (pre-tax): Maintenance (including acceleration of programs) $50 Replacement power per month $12-18 -----------------------------------------------------------------------------------
We have fully hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. Environmental Matters We believe we are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) 26 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 7D - Environmental Matters). We continue to evaluate our 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 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 or 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. 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 December 31, 2002, 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 $54.3 million as of December 31, 2002. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on our earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent we compete 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. We believe we are in material compliance with existing regulations, but are 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 our normal business operations are pending against FirstEnergy and its subsidiaries. The most significant are described below. Due to our merger with GPU, we own Unit 2 of the Three Mile Island Nuclear Plant (TMI-2). As a result of the 1979 TMI-2 accident, claims for alleged personal injury against JCP&L, Met-Ed, Penelec and GPU had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary 27 judgment filed by the GPU companies and dismissed the ten initial "test cases" which had been selected for a test case trial. On January 15, 2002, the District Court granted our motion for summary judgment on the remaining 2,100 pending claims. On February 14, 2002, the plaintiffs filed a notice of appeal of this decision (see Note 7E - Other Legal Proceedings). In December 2002, the Court of Appeals for the Third Circuit refused to hear the appeal which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service areas of many electric utilities, including JCP&L. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies seeking compensatory and punitive damages arising from the service interruptions of July 1999 in the JCP&L territory. In May 2001, the court denied without prejudice the defendant's motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that JCP&L is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion seeking permission to file an appeal on this denial of their motion was rejected by the New Jersey Appellate Division. We have also filed a motion for partial summary judgment that is currently pending before the Superior Court. We are unable to predict the outcome of these matters. It is FirstEnergy's understanding that, as of August 18, 2003, five individual described herein shareholder-plaintiffs have filed separate complaints against FirstEnergy Corp. 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. 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 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 (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. We have 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 only to conform with the revised 28 presentation (see Note 11 - Summary of Quarterly Financial Data). In addition, the related KWH sales and purchases statistics described above under Results of Operations were reclassified (7.2 billion KWH in 2002 and 3.7 KWH billion in 2001). The following table displays the impact of changing to a net presentation for our energy trading operations.
2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES ----------------------------------------------------------------------------------- RESTATED ----------------------------------------------------------------------- (SEE NOTES 2(L) AND 2(M)) --------------------------------------------------------------------------------- (IN MILLIONS) Total before adjustment $12,515 $10,378 Adjustment (268) (268) ------------------------------------------------------------------------------------- Total as reported $12,247 $10,110 ====================================================================================
SIGNIFICANT ACCOUNTING POLICIES We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Purchase Accounting - 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 (see Note 12). Regulatory Accounting Our 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 we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which we operate, a significant amount of regulatory assets have been recorded - $8.8 billion as of December 31, 2002. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. We continually monitor our derivative contracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for KWH 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: 29 - Net energy generated or purchased for retail load - Losses of energy over transmission and distribution lines - Mix of KWH usage by residential, commercial and industrial customers - KWH usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as our merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our SFAS 87 and 106 costs and liabilities from changes in key assumptions are as follows:
INCREASE IN COSTS FROM ADVERSE CHANGES IN KEY ASSUMPTIONS ----------------------------------------------------------------------------------------------- ASSUMPTION ADVERSE CHANGE PENSION OPEB TOTAL ----------------------------------------------------------------------------------------------- (IN MILLIONS) Discount rate Decrease by 0.25% $10.3 $ 7.4 $17.7 Long-term return on assets Decrease by 0.25% $ 6.9 $ 1.2 $ 8.1 Health care trend rate Increase by 1% na $20.7 $20.7 INCREASE IN MINIMUM LIABILITY Discount rate Decrease by 0.25% $99.4 na $99.4 ------------------------------------------------------------------------------------------------
30 As a result of the reduced market value of our pension plan assets, we were required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of $286.9 million and established a minimum liability of $548.6 million, recording an intangible asset of $78.5 million and reducing OCI by $444.2 million (recording a related deferred tax benefit of $312.8 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002 increased due to the lower discount rate assumed and reduced market value of plan assets as of December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $125 million and $45 million, respectively - a total of $170 million in 2003 as compared to 2002. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill The regulators in the jurisdictions that the Companies operate in do not provide recovery at goodwill. As a result, no amortization has been recorded subsequent to the adoption of SFAS 142. 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, we evaluate our 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 we 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. Our 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 our reporting units. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had $6.3 billion of goodwill that primarily relates to our regulated services segment. 31 RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED SFAS 143, "Accounting for Asset Retirement Obligations" 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 regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144. No impairment was indicated. The asset retirement liability at the date of adoption was $1.109 billion. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on decommissioning trust funds of $12 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn will be recoverable through their regulated rates. Therefore, we recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $175 million increase to income ($102 million net of tax). SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" SFAS 148 provides alternative approaches for voluntarily transitioning to the fair value method of accounting for stock-based compensation as described by SFAS 123 "Accounting for Stock-Based Compensation." Under current GAAP, we do not intend to adopt fair value accounting. It also amends SFAS 123 disclosure requirements for those companies applying APB 25, "Accounting for Stock Issued to Employees" and FASB Interpretation 44, "Accounting for Transactions involving Stock Compensation - an interpretation of APB Opinion No. 44." The amendment requires prominent display of differences between the SFAS 123 fair-value approach and the intrinsic-value approach described by APB 25 in a prescribed format. SFAS 148 also amends APB 28, "Interim Financial Reporting," to require that these disclosures be made on an interim basis. The new disclosure requirements are effective for 2002 year-end reporting (see Note 2B - Earnings Per Share) and for quarterly reporting beginning in 2003. Application of the alternative transition approaches is effective in 2003. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. 32 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 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 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 $11.6 million. 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. 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. 33 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 --------------------------------------------------------------------------------------------------------------------- RESTATED (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES: Electric utilities ......................................... $ 9,165,805 $ 5,729,036 $ 5,421,668 Unregulated businesses ..................................... 3,064,721 2,270,326 1,607,293 ------------ ----------- ----------- Total revenues ......................................... 12,230,526 7,999,362 7,028,961 ------------ ----------- ----------- EXPENSES: Fuel and purchased power ................................... 3,662,910 1,421,525 1,110,845 Purchased gas .............................................. 592,116 820,031 553,548 Other operating expenses (Note 2(M)) ....................... 3,888,909 2,727,794 2,378,296 Provision for depreciation and amortization (Note 2(M)) .... 1,305,843 889,550 933,684 General taxes .............................................. 650,329 455,340 547,681 ------------ ----------- ----------- Total expenses ......................................... 10,100,107 6,314,240 5,524,054 ------------ ----------- ----------- INCOME BEFORE INTEREST AND INCOME TAXES ....................... 2,130,419 1,685,122 1,504,907 ------------ ----------- ----------- NET INTEREST CHARGES: Interest expense ........................................... 910,272 519,131 493,473 Capitalized interest ....................................... (24,474) (35,473) (27,059) Subsidiaries' preferred stock dividends .................... 75,647 72,061 62,721 ------------ ----------- ----------- Net interest charges ................................... 961,445 555,719 529,135 ------------ ----------- ----------- INCOME TAXES .................................................. 528,694 474,457 376,802 ------------ ----------- ----------- INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES ............................... 640,280 654,946 598,970 ------------ ----------- ----------- Discontinued operations .................................... (87,476) -- -- Cumulative effect of accounting change (net of income tax benefit of $5,839,000) (Note 2(J)) ............ -- (8,499) -- ------------ ----------- ----------- NET INCOME .................................................... $ 552,804 $ 646,447 $ 598,970 ============ =========== =========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change .................................... $ 2.19 $ 2.85 $ 2.69 Discontinued operations (Note 2(M)) ........................ (0.30) -- -- Cumulative effect of accounting change (Note 2(J)) ......... -- (.03) -- ------------ ----------- ----------- Net income ................................................. $ 1.89 $ 2.82 $ 2.69 ============ =========== =========== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING ........... 293,194 229,512 222,444 ============ =========== =========== DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change .................................... $ 2.18 $ 2.84 $ 2.69 Discontinued operations (Note 2(M)) ........................ (0.30) -- -- Cumulative effect of accounting change (Note 2(J)) ......... -- (.03) -- ------------ ----------- ----------- Net income ................................................. $ 1.88 $ 2.81 $ 2.69 ============ =========== =========== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING ......... 294,421 230,430 222,726 ============ =========== =========== DIVIDENDS DECLARED PER SHARE OF COMMON STOCK .................. $ 1.50 $ 1.50 $ 1.50 ============ =========== ===========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 34 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2002 2001 --------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 2(M)) (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents ................................................ $ 196,301 $ 220,178 Receivables- Customers (less accumulated provisions of $52,514,000 and $65,358,000, respectively, for uncollectible accounts) ............................ 1,153,486 1,074,664 Other (less accumulated provisions of $12,851,000 and $7,947,000, respectively, for uncollectible accounts) ............................ 469,606 473,550 Materials and supplies, at average cost- Owned .................................................................. 253,047 256,516 Under consignment ...................................................... 174,028 141,002 Prepayments and other .................................................... 203,630 336,610 ----------- ----------- 2,450,098 2,502,520 ----------- ----------- ASSETS PENDING SALE (NOTE 3) ................................................ -- 3,418,225 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service ............................................................... 20,372,224 19,981,749 Less--Accumulated provision for depreciation ............................. 8,552,927 8,161,022 ----------- ----------- 11,819,297 11,820,727 Construction work in progress ............................................ 859,016 607,702 ----------- ----------- 12,678,313 12,428,429 ----------- ----------- INVESTMENTS: Capital trust investments (Note 4) ....................................... 1,079,435 1,166,714 Nuclear plant decommissioning trusts ..................................... 1,049,560 1,014,234 Letter of credit collateralization (Note 4) .............................. 277,763 277,763 Pension investments (Note 2(I)) .......................................... -- 273,542 Other .................................................................... 918,874 898,311 ----------- ----------- 3,325,632 3,630,564 ----------- ----------- DEFERRED CHARGES: Regulatory assets ........................................................ 8,753,401 8,912,584 Goodwill ................................................................. 6,278,072 5,600,918 Other (Note 2I) .......................................................... 900,837 858,273 ----------- ----------- 15,932,310 15,371,775 ----------- ----------- $34,386,353 $37,351,513 =========== =========== LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt and preferred stock ..................... $ 1,702,822 $ 1,867,657 Short-term borrowings (Note 6) ........................................... 1,092,817 614,298 Accounts payable ......................................................... 906,468 704,184 Accrued taxes ............................................................ 455,121 418,555 Other .................................................................... 1,093,815 1,064,763 ----------- ----------- 5,251,043 4,669,457 ----------- ----------- LIABILITIES RELATED TO ASSETS PENDING SALE (NOTE 3) ......................... -- 2,954,753 ----------- ----------- CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholders' equity .............................................. 7,050,661 7,398,599 Preferred stock of consolidated subsidiaries-- Not subject to mandatory redemption .................................... 335,123 480,194 Subject to mandatory redemption ........................................ 18,521 65,406 Subsidiary-obligated mandatorily redeemable preferred securities (Note 5(F)) 409,867 529,450 Long-term debt ........................................................... 10,872,216 11,433,313 ----------- ----------- 18,686,388 19,906,962 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes ........................................ 2,069,682 2,684,219 Accumulated deferred investment tax credits .............................. 236,184 260,532 Nuclear plant decommissioning costs ...................................... 1,243,558 1,201,599 Power purchase contract loss liability ................................... 3,136,538 3,566,531 Retirement benefits ...................................................... 1,564,930 838,943 Other .................................................................... 2,198,030 1,268,517 ----------- ----------- 10,448,922 9,820,341 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7) ................... ----------- ----------- $34,386,353 $37,351,513 =========== ===========
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 35 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION
AS OF DECEMBER 31, 2002 2001 ---------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 2(M)) (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) COMMON STOCKHOLDERS' EQUITY: Common stock, $0.10 par value - authorized 375,000,000 shares- 297,636,276 shares outstanding ............................. $ 29,764 $ 29,764 Other paid-in capital ........................................ 6,120,341 6,113,260 Accumulated other comprehensive loss (Note 5I) ............... (656,148) (169,003) Retained earnings (Note 5A) .................................. 1,634,981 1,521,805 Unallocated employee stock ownership plan common stock- 3,966,269 and 5,117,375 shares, respectively (Note 5B) ..... (78,277) (97,227) ----------- ----------- Total common stockholders' equity .......................... 7,050,661 7,398,599 ----------- -----------
NUMBER OF SHARES OPTIONAL OUTSTANDING REDEMPTION PRICE -------------------------- --------------------- 2002 2001 PER SHARE AGGREGATE ---------- ---------- --------- --------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Note 5D): Ohio Edison Company Cumulative, $100 par value- Authorized 6,000,000 shares Not Subject to Mandatory Redemption: 3.90% .................................. 152,510 152,510 $103.63 $15,804 15,251 15,251 4.40% .................................. 176,280 176,280 108.00 19,038 17,628 17,628 4.44% .................................. 136,560 136,560 103.50 14,134 13,656 13,656 4.56% .................................. 144,300 144,300 103.38 14,917 14,430 14,430 ---------- ---------- ------- -------- -------- 609,650 609,650 63,893 60,965 60,965 ---------- ---------- ------- -------- -------- Cumulative, $25 par value- Authorized 8,000,000 shares Not Subject to Mandatory Redemption: 7.75% .................................. -- 4,000,000 -- -- -- 100,000 ---------- ---------- ------- -------- -------- Total Not Subject to Mandatory Redemption ................... 609,650 4,609,650 $63,893 60,965 160,965 ========== ========== ======= -------- -------- Pennsylvania Power Company Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24% .................................. 40,000 40,000 103.13 $ 4,125 4,000 4,000 4.25% .................................. 41,049 41,049 105.00 4,310 4,105 4,105 4.64% .................................. 60,000 60,000 102.98 6,179 6,000 6,000 7.75% .................................. 250,000 250,000 -- -- 25,000 25,000 ---------- ---------- ------- -------- -------- Total Not Subject to Mandatory Redemption ............................. 391,049 391,049 $14,614 39,105 39,105 ========== ========== ======= -------- -------- Subject to Mandatory Redemption (Note 5E): 7.625% ................................. 142,500 150,000 103.81 $14,793 14,250 15,000 Redemption Within One Year ............... (750) (750) ---------- ---------- ------- -------- -------- Total Subject to Mandatory Redemption .. 142,500 150,000 $14,793 13,500 14,250 ========== ========== ======= -------- -------- Cleveland Electric Illuminating Company Cumulative, without par value- Authorized 4,000,000 shares Not Subject to Mandatory Redemption: $ 7.40 Series A ........................ 500,000 500,000 101.00 $50,500 50,000 50,000 $ 7.56 Series B ........................ -- 450,000 -- -- -- 45,071 Adjustable Series L .................... 474,000 474,000 100.00 47,400 46,404 46,404 $42.40 Series T ........................ -- 200,000 -- -- -- 96,850 ---------- ---------- ------- -------- -------- 974,000 1,624,000 97,900 96,404 238,325 Redemption Within One Year ............... -- (96,850) ---------- ---------- ------- -------- -------- Total Not Subject to Mandatory Redemption ............................. 974,000 1,624,000 $97,900 96,404 141,475 ========== ========== ======= -------- -------- Subject to Mandatory Redemption (Note 5E): $ 7.35 Series C ........................ 60,000 70,000 101.00 $ 6,060 6,021 7,030 $90.00 Series S ........................ -- 17,750 -- -- -- 17,268 ---------- ---------- ------- -------- -------- 60,000 87,750 6,060 6,021 24,298 Redemption Within One Year ............... (1,000) (18,010) ---------- ---------- ------- -------- -------- Total Subject to Mandatory Redemption .. 60,000 87,750 $ 6,060 5,021 6,288 ========== ========== ======= -------- --------
36 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
AS OF DECEMBER 31, 2002 2001 ----------------------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 2(M)) (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) NUMBER OF SHARES OPTIONAL OUTSTANDING REDEMPTION PRICE ------------------------- ---------------------- 2002 2001 PER SHARE AGGREGATE ---------- ---------- --------- --------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Cont'd) Toledo Edison Company Cumulative, $100 par value- Authorized 3,000,000 shares Not Subject to Mandatory Redemption: $ 4.25 .............................. 160,000 160,000 $ 104.63 $ 16,740 $ 16,000 $ 16,000 $ 4.56 .............................. 50,000 50,000 101.00 5,050 5,000 5,000 $ 4.25 .............................. 100,000 100,000 102.00 10,200 10,000 10,000 $ 8.32 .............................. -- 100,000 -- -- -- 10,000 $ 7.76 .............................. -- 150,000 -- -- -- 15,000 $ 7.80 .............................. -- 150,000 -- -- -- 15,000 $10.00 .............................. -- 190,000 -- -- -- 19,000 ---------- ---------- -------- -------- -------- 310,000 900,000 31,990 31,000 90,000 Redemption Within One Year ............ -- (59,000) ---------- ---------- -------- -------- -------- 310,000 900,000 31,990 31,000 31,000 ---------- ---------- -------- -------- -------- Cumulative, $25 par value- Authorized 12,000,000 shares Not Subject to Mandatory Redemption: $2.21 ............................... -- 1,000,000 -- -- -- 25,000 $2.365 .............................. 1,400,000 1,400,000 27.75 38,850 35,000 35,000 Adjustable Series A ................. 1,200,000 1,200,000 25.00 30,000 30,000 30,000 Adjustable Series B ................. 1,200,000 1,200,000 25.00 30,000 30,000 30,000 ---------- ---------- -------- -------- -------- 3,800,000 4,800,000 98,850 95,000 120,000 Redemption Within One Year ............ -- (25,000) ---------- ---------- -------- -------- -------- 3,800,000 4,800,000 98,850 95,000 95,000 ---------- ---------- -------- -------- -------- Total Not Subject to Mandatory Redemption ........................ 4,110,000 5,700,000 $130,840 126,000 126,000 ========== ========== ======== -------- -------- Jersey Central Power & Light Company Cumulative, $100 stated value- Authorized 15,600,000 shares Not Subject to Mandatory Redemption: 4.00% Series ........................ 125,000 125,000 106.50 $ 13,313 12,649 12,649 ========== ========== ======== -------- -------- Subject to Mandatory Redemption: 8.65% Series J ...................... -- 250,001 -- $ -- -- 26,750 7.52% Series K ...................... -- 265,000 -- -- -- 28,951 ---------- ---------- -------- -------- -------- -- 515,001 -- -- 55,701 Redemption Within One Year ............ -- (10,833) ---------- ---------- -------- -------- -------- Total Subject to Mandatory Redemption -- 515,001 $ -- -- 44,868 ========== ========== ======== -------- -------- SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED DEBENTURES OF SUBSIDIARIES (NOTE 5F): Ohio Edison Co. Cumulative, $25 stated value- Authorized 4,800,000 shares 9.00% ................................. -- 4,800,000 -- $ -- -- 120,000 ========== ========== ======== -------- -------- Cleveland Electric Illuminating Co. Cumulative, $25 stated value- Authorized 4,000,000 shares 9.00% ................................. 4,000,000 4,000,000 -- $ -- 100,000 100,000 ========== ========== ======== -------- -------- Jersey Central Power & Light Co. Cumulative, $25 stated value- Authorized 5,000,000 shares 8.56% ................................. 5,000,000 5,000,000 25.00 $125,000 125,244 125,250 ========== ========== ======== -------- -------- Metropolitan Edison Co. Cumulative, $25 stated value- Authorized 4,000,000 shares 7.35% ................................. 4,000,000 4,000,000 -- $ -- 92,409 92,200 ========== ========== ======== -------- -------- Pennsylvania Electric Co. Cumulative, $25 stated value- Authorized 4,000,000 shares 7.34% ................................. 4,000,000 4,000,000 -- $ -- 92,214 92,000 ========== ========== ======== -------- --------
37 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (NOTE 5G) (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (IN THOUSANDS) ------------------------------------------------------------------------------------------------------------------------------ FIRST MORTGAGE BONDS SECURED NOTES ------------------------------------------------------------------------------------------------------------------------------ AS OF DECEMBER 31, 2002 2001 2002 2001 -------- ---------- ---------- ---------- Ohio Edison Co. - Due 2002-2007 ................. 8.02% $230,000 $ 509,265 7.66% $ 186,549 $ 231,907 Due 2008-2012 ................. -- -- -- 7.00% 5,468 5,468 Due 2013-2017 ................. -- -- -- 5.09% 59,000 59,000 Due 2018-2022 ................. 8.75% 50,960 50,960 7.01% 60,443 60,443 Due 2023-2027 ................. 7.76% 168,500 168,500 -- -- -- Due 2028-2032 ................. -- -- -- 3.60% 249,634 249,634 Due 2033-2037 ................. -- -- -- 2.43% 71,900 71,900 -------- ---------- ---------- ---------- Total-Ohio Edison ................ 449,460 728,725 632,994 678,352 -------- ---------- ---------- ---------- Cleveland Electric Illuminating Co. - Due 2002-2007 ................. 8.97% 400,000 595,000 5.74% 680,175 713,205 Due 2008-2012 ................. 6.86% 125,000 125,000 7.43% 151,610 151,610 Due 2013-2017 ................. -- -- -- 7.88% 300,000 378,700 Due 2018-2022 ................. -- -- -- 6.24% 140,560 140,560 Due 2023-2027 ................. 9.00% 150,000 150,000 7.64% 218,950 218,950 Due 2028-2032 ................. -- -- -- 5.38% 5,993 5,993 Due 2033-2037 ................. -- -- -- 1.60% 30,000 -- -------- ---------- ---------- ---------- Total-Cleveland Electric ......... 675,000 870,000 1,527,288 1,609,018 -------- ---------- ---------- ---------- Toledo Edison Co. - Due 2002-2007 ................. 7.90% 178,725 179,125 6.19% 229,700 258,700 Due 2008-2012 ................. -- -- -- -- -- -- Due 2013-2017 ................. -- -- -- -- -- -- Due 2018-2022 ................. -- -- -- 7.89% 114,000 129,000 Due 2023-2027 ................. -- -- -- 7.31% 60,800 60,800 Due 2028-2032 ................. -- -- -- 5.38% 3,751 3,751 Due 2033-2037 ................. -- -- -- 1.68% 51,100 30,900 -------- ---------- ---------- ---------- Total-Toledo Edison .............. 178,725 179,125 459,351 483,151 -------- ---------- ---------- ---------- Pennsylvania Power Co. - Due 2002-2007 ................. 7.19% 79,370 80,344 2.99% 10,300 10,300 Due 2008-2012 ................. 9.74% 4,870 4,870 -- -- -- Due 2013-2017 ................. 9.74% 4,870 4,870 3.12% 29,525 29,525 Due 2018-2022 ................. 8.58% 29,231 29,231 3.94% 31,282 31,282 Due 2023-2027 ................. 7.63% 6,500 6,500 6.15% 12,700 27,200 Due 2028-2032 ................. -- -- -- 5.79% 23,172 23,172 -------- ---------- ---------- ---------- Total-Penn Power ................. 124,841 125,815 106,979 121,479 -------- ---------- ---------- ---------- Jersey Central Power & Light Co. - Due 2002-2007 ................. 6.90% 442,674 541,260 5.60% 241,135 150,000 Due 2008-2012 ................. 7.13% 5,040 5,040 5.39% 52,273 -- Due 2013-2017 ................. 7.10% 12,200 12,200 6.01% 176,592 -- Due 2018-2022 ................. 8.62% 76,586 170,000 -- -- -- Due 2023-2027 ................. 7.37% 365,000 365,000 -- -- -- Due 2028-2032 ................. -- -- -- -- -- -- Due 2033-2037 ................. -- -- -- -- -- -- Due 2038-2042 ................. -- -- -- -- -- -- -------- ---------- ---------- ---------- Total-Jersey Central ............. 901,500 1,093,500 470,000 150,000 -------- ---------- ---------- ---------- Metropolitan Edison Co. - Due 2002-2007 ................. 6.71% 202,175 262,175 5.79% 150,000 100,000 Due 2008-2012 ................. 6.00% 6,525 6,525 -- -- -- Due 2013-2017 ................. -- -- -- -- -- -- Due 2018-2022 ................. 7.86% 88,500 88,500 -- -- -- Due 2023-2027 ................. 7.55% 133,690 133,690 -- -- -- Due 2028-2032 ................. -- -- -- -- -- -- Due 2033-2037 ................. -- -- -- -- -- -- Due 2038-2042 ................. -- -- -- -- -- -- -------- ---------- ---------- ---------- Total-Metropolitan Edison ........ 430,890 490,890 150,000 100,000 -------- ---------- ---------- ----------
LONG-TERM DEBT (NOTE 5G) (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (IN THOUSANDS) ------------------------------------------------------------------------------------------------------------- UNSECURED NOTES TOTAL ------------------------------------------------------------------------------------------------------------- AS OF DECEMBER 31, 2002 2001 2002 2001 -------- -------- ----------- ----------- RESTATED (SEE NOTE 2(M)) Ohio Edison Co. - Due 2002-2007 ................. 4.17% $441,725 $441,725 Due 2008-2012 ................. -- -- -- Due 2013-2017 ................. -- -- -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- Due 2033-2037 ................. -- -- -- -------- -------- ----------- ----------- Total-Ohio Edison ................ 441,725 441,725 $ 1,524,179 $ 1,848,802 -------- -------- ----------- ----------- Cleveland Electric Illuminating Co. - Due 2002-2007 ................. 5.58% 27,700 27,700 Due 2008-2012 ................. -- -- -- Due 2013-2017 ................. 6.00% 78,700 -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- Due 2033-2037 ................. -- -- -- -------- -------- ----------- ----------- Total-Cleveland Electric ......... 106,400 27,700 2,308,688 2,506,718 -------- -------- ----------- ----------- Toledo Edison Co. - Due 2002-2007 ................. 4.83% 91,100 226,130 Due 2008-2012 ................. 10.00% 760 760 Due 2013-2017 ................. -- -- -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- Due 2033-2037 ................. -- -- -- -------- -------- ----------- ----------- Total-Toledo Edison .............. 91,860 226,890 729,936 889,166 -------- -------- ----------- ----------- Pennsylvania Power Co. - Due 2002-2007 ................. 4.39% 19,700 5,200 Due 2008-2012 ................. -- -- -- Due 2013-2017 ................. -- -- -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- -------- -------- ----------- ----------- Total-Penn Power ................. 19,700 5,200 251,520 252,494 -------- -------- ----------- ----------- Jersey Central Power & Light Co. - Due 2002-2007 ................. 7.69% 93 107 Due 2008-2012 ................. 7.69% 134 134 Due 2013-2017 ................. 7.69% 193 193 Due 2018-2022 ................. 7.69% 280 280 Due 2023-2027 ................. 7.69% 406 406 Due 2028-2032 ................. 7.69% 588 588 Due 2033-2037 ................. 7.69% 851 851 Due 2038-2042 ................. 7.69% 439 439 -------- -------- ----------- ----------- Total-Jersey Central ............. 2,984 2,998 1,374,484 1,246,498 -------- -------- ----------- ----------- Metropolitan Edison Co. - Due 2002-2007 ................. 7.69% 185 214 Due 2008-2012 ................. 7.69% 267 267 Due 2013-2017 ................. 7.69% 387 387 Due 2018-2022 ................. 7.69% 560 560 Due 2023-2027 ................. 7.69% 812 812 Due 2028-2032 ................. 7.69% 1,176 1,176 Due 2033-2037 ................. 7.69% 1,703 1,703 Due 2038-2042 ................. 7.69% 878 878 -------- -------- ----------- ----------- Total-Metropolitan Edison ........ 5,968 5,997 586,858 596,887 -------- -------- ----------- -----------
38 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (CONT'D) (IN THOUSANDS) --------------------------------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS SECURED NOTES --------------------------------------------------------------------------------------------------------------------------- AS OF DECEMBER 31, 2002 2001 2002 2001 ---------- ---------- ---------- ---------- RESTATED (SEE NOTE 2(M)) Pennsylvania Electric Co. - Due 2002-2007 6.13% $ 3,905 $ 4,110 -- $ -- $ -- Due 2008-2012 5.35% 24,310 24,310 -- -- -- Due 2013-2017 -- -- -- -- -- -- Due 2018-2022 5.80% 20,000 20,000 -- -- -- Due 2023-2027 6.05% 25,000 25,000 -- -- -- Due 2028-2032 -- -- -- -- -- -- Due 2033-2037 -- -- -- -- -- -- Due 2038-2042 -- -- -- -- -- -- ---------- ---------- ---------- ---------- Total-Pennsylvania Electric 73,215 73,420 -- -- ---------- ---------- ---------- ---------- FirstEnergy Corp. - Due 2002-2007 -- -- -- -- -- -- Due 2008-2012 -- -- -- -- -- -- Due 2013-2017 -- -- -- -- -- -- Due 2018-2022 -- -- -- -- -- -- Due 2023-2027 -- -- -- -- -- -- Due 2028-2032 -- -- -- -- -- -- ---------- ---------- ---------- ---------- Total-FirstEnergy -- -- -- -- ---------- ---------- ---------- ---------- OES Fuel -- -- -- -- 81,515 AFN Finance Co. No. 1 -- -- -- -- 15,000 AFN Finance Co. No. 3 -- -- -- -- 4,000 Bay Shore Power -- -- 6.24% 143,200 145,400 MARBEL Energy Corp. -- -- -- -- -- Facilities Services Group -- -- 4.86% 13,205 15,735 FirstEnergy Generation -- -- -- -- -- FirstEnergy Properties -- -- 7.89% 9,679 9,902 Warrenton River Terminal -- -- 5.25% 634 776 GPU Capital* -- -- -- -- -- GPU Power -- -- 7.14% 174,760 239,373 ---------- ---------- ---------- ---------- Total $2,833,631 $3,561,475 $3,688,090 $3,653,701 ========== ========== ========== ========== Capital lease obligations ................................................................................................. Net unamortized premium on debt* .......................................................................................... Long-term debt due within one year*........................................................................................ Total long-term debt* ..................................................................................................... TOTAL CAPITALIZATION* ..................................................................................................... ---------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (CONT'D) (IN THOUSANDS) ----------------------------------------------------------------------------------------------------------------------- UNSECURED NOTES TOTAL ----------------------------------------------------------------------------------------------------------------------- AS OF DECEMBER 31, 2002 2001 2002 2001 ---------- ---------- -------------- -------------- Pennsylvania Electric Co. - Due 2002-2007 5.86% $ 133,093 $ 183,107 Due 2008-2012 6.55% 135,134 135,134 Due 2013-2017 7.69% 193 193 Due 2018-2022 6.63% 125,280 125,280 Due 2023-2027 7.69% 406 406 Due 2028-2032 7.69% 588 588 Due 2033-2037 7.69% 851 851 Due 2038-2042 7.69% 439 439 ---------- ---------- -------------- -------------- Total-Pennsylvania Electric 395,984 445,998 $ 469,199 $ 519,418 ---------- ---------- -------------- -------------- FirstEnergy Corp. - Due 2002-2007 5.28% 1,695,000 1,550,000 Due 2008-2012 6.45% 1,500,000 1,500,000 Due 2013-2017 -- -- -- Due 2018-2022 -- -- -- Due 2023-2027 -- -- -- Due 2028-2032 7.38% 1,500,000 1,500,000 ---------- ---------- -------------- -------------- Total-FirstEnergy 4,695,000 4,550,000 4,695,000 4,550,000 ---------- ---------- -------------- -------------- OES Fuel -- -- -- -- 81,515 AFN Finance Co. No. 1 -- -- -- -- 15,000 AFN Finance Co. No. 3 -- -- -- -- 4,000 Bay Shore Power -- -- -- 143,200 145,400 MARBEL Energy Corp. -- -- 569 -- 569 Facilities Services Group -- -- -- 13,205 15,735 FirstEnergy Generation 5.00% 15,000 -- 15,000 -- FirstEnergy Properties -- -- -- 9,679 9,902 Warrenton River Terminal -- -- -- 634 776 GPU Capital* 5.78% 101,467 1,629,582 101,467 1,629,582 GPU Power 11.87% 67,372 56,048 242,132 295,421 ---------- ---------- -------------- -------------- Total $5,943,460 $7,392,707 12,465,181 14,607,883 ========== ========== -------------- -------------- Capital lease obligations ....................................................... 15,761 19,390 Net unamortized premium on debt* ................................................ 92,346 213,834 Long-term debt due within one year* ............................................. (1,701,072) (1,975,755) -------------- -------------- Total long-term debt* ........................................................... 10,872,216 12,865,352 -------------- -------------- TOTAL CAPITALIZATION* ........................................................... $ 18,686,388 $ 21,339,001 -----------------------------------------------------------------------------------------------------------------------
* 2001 includes amounts in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 39 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Restated)
ACCUMULATED OTHER OTHER COMPREHENSIVE NUMBER PAR PAID-IN COMPREHENSIVE INCOME OF SHARES VALUE CAPITAL INCOME (LOSS) ------------- ------------- ------------- ------------- ------------- (DOLLARS IN THOUSANDS) Balance, January 1, 2000 ................... 232,454,287 $ 23,245 $ 3,722,375 $ (195) Net income .............................. $ 598,970 Minimum liability for unfunded retirement benefits, net of $85,000 of income taxes ............... (134) (134) Unrealized gain on investment in securities available for sale ......... 922 922 ------------- Comprehensive income .................... $ 599,758 ============= Reacquired common stock ................. (7,922,707) (792) (194,210) Allocation of ESOP shares ............... 3,656 Cash dividends on common stock .......... Balance, December 31, 2000 ................. 224,531,580 22,453 3,531,821 593 GPU acquisition ......................... 73,654,696 7,366 2,586,097 Net income .............................. $ 646,447 Minimum liability for unfunded retirement benefits, net of $(182,000) of income taxes ................................. (268) (268) Unrealized loss on derivative hedges, net of $(116,521,000) of income taxes ..... (169,408) (169,408) Unrealized gain on investments, net of $56,000 of income taxes ............... 81 81 Unrealized currency translation adjust- ments, net of $(1,000) of income taxes (1) (1) ------------- Comprehensive income .................... $ 476,851 ============= Reacquired common stock ................. (550,000) (55) (15,253) Allocation of ESOP shares ............... 10,595 Cash dividends on common stock .......... Balance, December 31, 2001 ................. 297,636,276 29,764 6,113,260 (169,003) Net income .............................. $ 552,804 Minimum liability for unfunded retirement benefits, net of $(316,681,000) of income taxes .......................... (449,615) (449,615) Unrealized gain on derivative hedges, net of $37,458,000 of income taxes ........ 59,187 59,187 Unrealized loss on investments, net of $(4,266,000) of income taxes .......... (5,269) (5,269) Unrealized currency translation adjust- ments ................................. (91,448) (91,448) ------------- Comprehensive income .................... $ 65,659 ============= Stock options exercised ................. (8,169) Allocation of ESOP shares ............... 15,250 Cash dividends on common stock .......... Balance, December 31, 2002 ................. 297,636,276 $ 29,764 $ 6,120,341 $ (656,148) ============= ============= ============= ===========
UNALLOCATED ESOP RETAINED COMMON EARNINGS STOCK ------------- ------------- Balance, January 1, 2000 ................... $ 945,241 $ (126,776) Net income .............................. 598,970 Minimum liability for unfunded retirement benefits, net of $85,000 of income taxes ............... Unrealized gain on investment in securities available for sale ......... Comprehensive income .................... Reacquired common stock ................. Allocation of ESOP shares ............... 15,044 Cash dividends on common stock .......... (334,220) ------------- Balance, December 31, 2000 ................. 1,209,991 (111,732) GPU acquisition ......................... Net income .............................. 646,447 Minimum liability for unfunded retirement benefits, net of $(182,000) of income taxes ................................. Unrealized loss on derivative hedges, net of $(116,521,000) of income taxes ..... Unrealized gain on investments, net of $56,000 of income taxes ............... Unrealized currency translation adjust- ments, net of $(1,000) of income taxes Comprehensive income .................... Reacquired common stock ................. Allocation of ESOP shares ............... 14,505 Cash dividends on common stock .......... (334,633) ------------- Balance, December 31, 2001 ................. 1,521,805 (97,227) Net income .............................. 552,804 Minimum liability for unfunded retirement benefits, net of $(316,681,000) of income taxes .......................... Unrealized gain on derivative hedges, net of $37,458,000 of income taxes ........ Unrealized loss on investments, net of $(4,266,000) of income taxes .......... Unrealized currency translation adjust- ments ................................. Comprehensive income .................... Stock options exercised ................. Allocation of ESOP shares ............... 18,950 Cash dividends on common stock .......... (439,628) ------------- Balance, December 31, 2002 ................. $ 1,634,981 (78,277) ============= =============
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 40 CONSOLIDATED STATEMENTS OF PREFERRED STOCK
NOT SUBJECT TO SUBJECT TO MANDATORY REDEMPTION MANDATORY REDEMPTION ----------------------- ---------------------- PAR OR PAR OR NUMBER STATED NUMBER STATED OF SHARES VALUE OF SHARES VALUE ---------- -------- ---------- -------- (DOLLARS IN THOUSANDS) Balance, January 1, 2000 12,324,699 $648,395 5,269,680 $294,710 Redemptions- 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series E (3,000) (3,000) $91.50 Series Q (10,714) (10,714) $90.00 Series S (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C (69) $88.00 Series R (3,872) $90.00 Series S (5,734) -------- Balance, December 31, 2000 12,324,699 648,395 5,177,216 246,571 GPU acquisition 125,000 12,649 13,515,001 365,151 Issues- 9.00% Series 4,000,000 100,000 Redemptions- 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series R (50,000) (50,000) $91.50 Series Q (10,716) (10,716) $90.00 Series S (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C (11) $88.00 Series R (1,128) $90.00 Series S (668) -------- Balance, December 31, 2001 12,449,699 661,044 22,552,751 624,449 Redemptions- 7.75% Series (4,000,000) (100,000) $7.56 Series B (450,000) (45,071) $42.40 Series T (200,000) (96,850) $8.32 Series (100,000) (10,000) $7.76 Series (150,000) (15,000) $7.80 Series (150,000) (15,000) $10.00 Series (190,000) (19,000) $2.21 Series (1,000,000) (25,000) 7.625% Series (7,500) (750) $7.35 Series C (10,000) (1,000) $90.00 Series S (17,750) (17,010) 8.65% Series J (250,001) (26,750) 7.52% Series K (265,000) (28,951) 9.00% Series (4,800,000) (120,000) Amortization of fair market value adjustments- $ 7.35 Series C (9) $90.00 Series S (258) 8.56% Series (6) 7.35% Series 209 7.34% Series 214 -------- Balance, December 31, 2002 6,209,699 $335,123 17,202,500 $430,138 ========== ======== ========== ========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 41 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 -------------------------------- ----------- ----------- ----------- (SEE NOTES 2 (L) AND (M)) (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income...................................................... $ 552,804 $ 646,447 $ 598,970 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization................ 1,305,843 889,550 933,684 Nuclear fuel and lease amortization........................ 80,507 98,178 113,330 Other amortization, net (Note 2)........................... (16,593) (11,927) (11,635) Deferred costs recoverable as regulatory assets............ (362,956) (31,893) -- Avon investment impairment (Note 3)........................ 50,000 -- -- Deferred income taxes, net................................. 56,732 31,625 (79,429) Investment tax credits, net................................ (28,325) (22,545) (30,732) Cumulative effect of accounting change..................... -- 14,338 -- Discontinued Operations (See Note 2(M)).................... 87,476 -- -- Receivables................................................ (85,307) 53,099 (150,520) Materials and supplies..................................... (29,557) (50,052) (29,653) Accounts payable........................................... 220,762 (84,572) 118,282 Deferred lease costs....................................... (84,800) -- -- Other (Note 9)............................................. 168,701 (250,564) 45,529 ----------- ----------- ----------- Net cash provided from operating activities.............. 1,915,287 1,281,684 1,507,826 ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Preferred stock.............................................. -- 96,739 -- Long-term debt............................................... 668,676 4,338,080 307,512 Short-term borrowings, net................................... 478,520 -- 281,946 Redemptions and Repayments- Common stock................................................. -- (15,308) (195,002) Preferred stock.............................................. (522,223) (85,466) (38,464) Long-term debt............................................... (1,308,814) (394,017) (901,764) Short-term borrowings, net................................... -- (1,641,484) -- Common Stock Dividend Payments.................................. (439,628) (334,633) (334,220) ----------- ----------- ----------- Net cash provided from (used for) financing activities... (1,123,469) 1,963,911 (879,992) ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: GPU acquisition, net of cash.................................... -- (2,013,218) -- Property additions.............................................. (997,723) (852,449) (587,618) Proceeds from sale of Midlands.................................. 155,034 -- -- Avon cash and cash equivalents (Note 3)......................... 31,326 -- -- Net assets held for sale........................................ (31,326) -- -- Cash investments (Note 2)....................................... 81,349 24,518 17,449 Other (Note 9).................................................. (54,355) (233,526) (120,195) ----------- ----------- ----------- Net cash used for investing activities................... (815,695) (3,074,675) (690,364) ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents............ (23,877) 170,920 (62,530) Cash and cash equivalents at beginning of year.................. 220,178 49,258 111,788 ----------- ----------- ----------- Cash and cash equivalents at end of year*....................... $ 196,301 $ 220,178 $ 49,258 =========== =========== =========== SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)........................ $ 881,515 $ 425,737 $ 485,374 Income taxes................................................. $ 389,180 $ 433,640 $ 512,182
* 2001 excludes amounts in "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 42 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF TAXES
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 200O -------------------------------- ----------- ----------- ----------- RESTATED (SEE NOTE 2(M)) (IN THOUSANDS) GENERAL TAXES: Real and personal property...................................... $ 218,683 $ 176,916 $ 281,374 State gross receipts*........................................... 132,622 102,335 221,385 Kilowatt-hour excise*........................................... 219,970 117,979 -- Social security and unemployment................................ 46,345 44,480 39,134 Other........................................................... 32,709 13,630 5,788 ----------- ----------- ----------- Total general taxes...................................... $ 650,329 $ 455,340 $ 547,681 =========== =========== =========== PROVISION FOR INCOME TAXES: Currently payable- Federal...................................................... $ 326,417 $ 375,108 $ 467,045 State........................................................ 104,866 84,322 19,918 Foreign...................................................... 20,624 108 -- ----------- ----------- ----------- 451,908 459,538 486,963 ----------- ----------- ----------- Deferred, net- Federal...................................................... 81,934 37,888 (60,831) State........................................................ 7,759 (6,177) (18,598) Foreign...................................................... 13,600 (86) -- ----------- ----------- ----------- 103,293 31,625 (79,429) ----------- ----------- ----------- Investment tax credit amortization.............................. (26,507) (22,545) (30,732) ----------- ----------- ----------- Total provision for income taxes......................... $ 528,694 $ 468,618 $ 376,802 =========== =========== =========== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes................... $1,081,498 $ 1,115,065 $ 975,772 =========== =========== =========== Federal income tax expense at statutory rate.................... $ 390,273 $ 341,520 Increases (reductions) in taxes resulting from- $ 378,524 Amortization of investment tax credits....................... (26,507) (22,545) (30,732) State income taxes, net of federal income tax benefit........ 73,220 50,794 1,133 Amortization of tax regulatory assets........................ 29,296 30,419 38,702 Amortization of goodwill..................................... -- 18,416 18,420 Preferred stock dividends.................................... 13,634 19,733 18,172 Valuation reserve for tax benefits........................... 48,587 -- -- Other, net................................................... 11,440 (18,472) (10,413) ----------- ----------- ----------- Total provision for income taxes......................... $ 528,694 $ 468,618 $ 376,802 =========== =========== =========== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences.................................... $2,052,594 $ 1,996,937 $ 1,245,297 Customer receivables for future income taxes.................. 144,073 178,683 62,527 Competitive transition charge................................. 1,408,232 1,289,438 1,070,161 Deferred sale and leaseback costs............................. (99,647) (77,099) (128,298) Nonutility generation costs................................... (228,476) (178,393) -- Unamortized investment tax credits............................ (78,227) (86,256) (85,641) Unused alternative minimum tax credits........................ -- -- (32,215) Other comprehensive income.................................... (240,663) (115,395) -- Above market leases........................................... (490,698) -- -- Other (Notes 2 and 9)......................................... (397,506) (323,696) (37,724) ----------- ----------- ----------- Net deferred income tax liability**.................... $2,069,682 $ 2,684,219 $ 2,094,107 =========== =========== ===========
* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. ** 2001 excludes amounts in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 43 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. GENERAL: The consolidated financial statements include FirstEnergy Corp., a public utility holding company, and its principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). ATSI owns and operates FirstEnergy's transmission facilities within the service areas of OE, CEI and TE (Ohio Companies) and Penn. The utility subsidiaries are referred to throughout as "Companies." FirstEnergy's 2001 results include the results of JCP&L, Met-Ed and Penelec from the period they were acquired on November 7, 2001 through December 31, 2001. The consolidated financial statements also include FirstEnergy's other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group, Inc.; 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 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 in consolidation. 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 preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform with the current year presentation, as described further in Notes 8 and 9. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (A) CONSOLIDATION- FirstEnergy consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when FirstEnergy is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, FirstEnergy applies the cost method. (B) EARNINGS PER SHARE- Basic earnings per share are computed using the weighted average of actual common shares outstanding as the denominator. Diluted earnings per share reflect the weighted average of actual common shares outstanding plus the potential additional common shares that could result if dilutive securities and agreements were exercised in the denominator. In 2002, 2001 and 2000, stock based awards to purchase shares of common stock totaling 3.4 million, 0.1 million and 1.8 million, respectively, were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. The numerators for the calculations of basic and diluted earnings per share are Income Before Cumulative Effect of Changes in Accounting and Net Income. The following table reconciles the denominators for basic and diluted earnings per share:
DENOMINATOR FOR EARNINGS PER SHARE CALCULATIONS ----------------------------------------------- YEARS ENDED DECEMBER 31, 2002 2001 2000 ------- ------- ------- (IN THOUSANDS) Denominator for basic earnings per share (weighted average shares actually outstanding) 293,194 229,512 222,444 Assumed exercise of dilutive securities or agreements to issue common stock 1,227 918 282 ------- ------- ------- Denominator for diluted earnings per share 294,421 230,430 222,726 ======= ======= =======
44 (C) REVENUES- The Companies' principal business is providing electric service to customers in Ohio, Pennsylvania and New Jersey. The Companies' retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. See Note 9 - Other Information for discussion of reporting of independent system operator (ISO) transactions. Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2002 or 2001, with respect to any particular segment of FirstEnergy's customers. CEI and TE sell substantially all of their retail customers' receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (an SFAS 140 "qualified special purpose entity") under an asset-backed securitization agreement. Transfers are made in return for an interest in the trust (41% as of December 31, 2002), which is stated at fair value, reflecting adjustments for anticipated credit losses. The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subsequent measurements of the retained interest under SFAS 115 (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust. Of the $272 million sold to the trust and outstanding as of December 31, 2002, FirstEnergy's retained interests in $111 million of the receivables are included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on the Consolidated Balance Sheets were reduced by approximately $161 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2002 totaled approximately $2.2 billion. CEI and TE processed receivables for the trust and received servicing fees of approximately $3.8 million in 2002. Expenses associated with the factoring discount related to the sale of receivables were $4.7 million in 2002. 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 (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. FirstEnergy has 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 only to conform with the revised presentation (see Note 11 - Summary of Quarterly Financial Data). In addition, the related KWH sales and purchases statistics described under Management's Discussion and Analysis - Results of Operations were reclassified (7.2 billion KWH in 2002 and 3.7 billion KWH in 2001). The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations.
2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES ------------------------------------------- -------- -------- RESTATED (SEE NOTES 2(L) AND 2(M)) (IN MILLIONS) Total before adjustment $12,499 $10,368 Adjustment (268) (268) ------- -------- Total as reported $12,231 $10,100 ======= ========
(D) 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; - establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; - allowing recovery of potentially stranded investment (or transition costs); - itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the Companies' electric generation businesses; and 45 - 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 the Ohio Companies as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 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 2(M) for consideration of above market lease costs) 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 megawatts (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 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 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 February 2002, JCP&L received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs. The NJBPU order also provided for a usage-based non-bypassable transition bond charge and for the transfer of the bondable transition property to another entity. JCP&L sold $320 million of transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet (see Note 5). 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 46 nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2002, the accumulated deferred cost balance totaled approximately $549 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. On August 1, 2002, JCP&L submitted two rate filings with the NJBPU. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current 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. The Administrative Law Judge's recommended decision is due in June 2003 (see Note 13) and the NJBPU's subsequent decision is due in July 2003. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The auction results were approved by the NJBPU in February 2002, removing 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 will sell all self-supplied energy (NUGs and owned generation) to the wholesale market with offsets to its deferred energy cost 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 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 of $55.8 million ($32.6 million net of tax) to income 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. 47 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. 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 CTC recovery of PLR costs above Met-Ed's and Penelec's capped generation rates will not have a future adverse financial impact. 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, which initially ran through the end of 2002, was extended 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 assumes the supply obligation and the energy 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 obligation through 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. The application of SFAS 71 has been discontinued with respect to the Companies' generation operations. The SEC issued interpretive guidance regarding asset impairment measurement, concluding that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, $1.8 billion of impaired plant investments ($1.2 billion, $227 million, $304 million and $53 million for OE, Penn, CEI and TE, respectively) were recognized as regulatory assets recoverable as transition costs through future regulatory cash flows. The following summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, compared with the respective company's total assets as of December 31, 2002.
SFAS 71 DISCONTINUED NET ASSETS TOTAL ASSETS ------------ ------------ (IN MILLIONS) OE $ 947 $7,740 CEI 1,406 6,510 TE 559 2,862 Penn 82 908 JCP&L 44 8,053 Met-Ed 17 3,565 Penelec -- 3,163
(E) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (except for nuclear generating units and the international properties which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility - its net book value was approximately $21.3 million as of December 31, 2002. FirstEnergy also shares ownership interests in various foreign properties with an aggregate net book value of $154 million, representing the fair value of FirstEnergy's interest. FirstEnergy's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for the Companies' electric plant in 2002, 2001 and 2000 (post merger periods only for JCP&L, Met-Ed and Penelec) are shown in the following table: 48
ANNUAL COMPOSITE DEPRECIATION RATE ------------------------- 2002 2001 2000 ---- ---- ---- OE 2.7% 2.7% 2.8% CEI 3.4 3.2 3.4 TE 3.9 3.5 3.4 Penn 2.9 2.9 2.6 JCP&L 3.5 3.4 Met-Ed 3.0 3.0 Penelec 3.0 2.9
Annual depreciation expense in 2002 included approximately $125 million for future decommissioning costs applicable to the Companies' ownership and leasehold interests in five nuclear generating units (Davis-Besse Unit 1, Beaver Valley Units 1 and 2, Perry Unit 1 and Three Mile Island Unit 2 (TMI-2)), a demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a wholly-owned subsidiary of JCP&L, Met-Ed and Penelec, and decommissioning liabilities for previously divested GPU nuclear generating units. The Companies' share of the future obligation to decommission these units is approximately $2.6 billion in current dollars and (using a 4.0% escalation rate) approximately $5.3 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Decommissioning of the demonstration nuclear reactor is expected to be completed in 2003; payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin. The Companies have recovered approximately $671 million for decommissioning through their electric rates from customers through December 31, 2002. The Companies have also recognized an estimated liability of approximately $37 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability 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 has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, 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. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $1.109 billion. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.243 billion. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that the ultimate nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn will be tracked and recovered through their regulated rates. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning for those companies. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $175 million increase to income ($102 million net of tax). The FASB approved SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of FirstEnergy's goodwill is required. The impairment analysis includes a significant source of cash representing EUOC recovery of transition costs as described above under "Regulatory Matters." FirstEnergy does not believe that completion of transition cost recovery will result in an impairment of goodwill relating to its regulated business segment. Prior to the adoption of SFAS 142, FirstEnergy amortized about $57 million ($.23 per share of common stock) of goodwill annually. There was no goodwill amortization in 2001 associated with the GPU merger under the provisions of the new standard. 49 The following table displays what net income and earnings per share would have been if goodwill amortization had been excluded in 2001 and 2000:
2002 2001 2000 -------- -------- -------- RESTATED (SEE NOTE 2(M)) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Reported net income.............................. $552,804 $646,447 $598,970 Goodwill amortization (net of tax)............... -- 54,584 54,138 -------- -------- -------- Adjusted net income.............................. $552,804 $701,031 $653,108 ======== ======== ======== Basic earnings per common share: Reported earnings per share................... $1.89 $2.82 $2.69 Goodwill amortization......................... -- 0.23 0.25 -------- -------- -------- Adjusted earnings per share................... $1.89 $3.05 $2.94 ======== ======== ======== Diluted earnings per common share: Reported earnings per share................... $1.88 $2.81 $2.69 Goodwill amortization......................... -- 0.23 0.24 -------- -------- -------- Adjusted earnings per share................... $1.88 $3.04 $2.93 ======== ======== ========
The net change of $677 million in the goodwill balance as of December 31, 2002 compared to the December 31, 2001 balance primarily reflects the $135.3 million after-tax effect of the Pennsylvania PLR reserve discussed in Note 2D - Regulatory Matters - Pennsylvania and finalization of the initial purchase price allocation for the GPU acquisition (see Note 12). (F) NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the rate of consumption. (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 5C). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows:
2002 2001 2000 ----- ----- ----- Valuation assumptions: Expected option term (years) 8.1 8.3 7.6 Expected volatility 23.31% 23.45% 21.77% Expected dividend yield 4.36% 5.00% 6.68% Risk-free interest rate 4.60% 4.67% 5.28% Fair value per option $6.45 $4.97 $2.86
The effects of applying fair value accounting to the FirstEnergy's stock options would be to reduce net income and earnings per share. The following table summarizes this effect. 50
2002 2001 2000 -------- -------- -------- RESTATED (SEE NOTE 2(M) (IN THOUSANDS) Net Income, as reported $552,804 $646,447 $598,970 Add back compensation expense reported in net income, net of tax (based on APB 25) 166 25 144 Deduct compensation expense based upon fair value, net of tax (8,825) (3,748) (1,736) -------- -------- -------- Adjusted net income $544,145 $642,724 $597,378 -------- -------- -------- Earnings Per Share of Common Stock - Basic As Reported $ 1.89 $ 2.82 $ 2.69 Adjusted $ 1.86 $ 2.80 $ 2.69 Diluted As Reported $ 1.88 $ 2.81 $ 2.69 Adjusted $ 1.85 $ 2.79 $ 2.69
(H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Valuation allowances of $465 million were established and included in the Consolidated Balance Sheet as of December 31, 2002, primarily associated with certain fair value adjustments (see Note 12) and capital losses related to the divestitures of international assets owned by the former GPU, Inc. prior to its acquisition by FirstEnergy. Of the total valuation allowance, $325 million relates to capital loss carryforwards that expire at the end of 2007. Management is unable to predict whether sufficient capital gains will be generated to utilize all of these capital loss carryforwards. Any ultimate utilization of these capital loss carryforwards for which valuation allowances have been established would reduce goodwill. (I) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the GPU pension plans were merged with the FirstEnergy plan. FirstEnergy uses the projected unit credit method for funding purposes and was not required to make pension contributions during the three years ended December 31, 2002. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. Costs for the year 2001 include the former GPU companies' pension and other postretirement benefit costs for the period November 7, 2001 through December 31, 2001. FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. FirstEnergy pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by FirstEnergy. FirstEnergy recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2.889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million and established a minimum liability of $548.6 million, recording an intangible asset of $78.5 million and reducing OCI by $444.2 million (recording a related deferred tax asset of $312.8 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. 51 The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of December 31:
OTHER PENSION BENEFITS POSTRETIREMENT BENEFITS ------------------------ ------------------------ 2002 2001 2002 2001 --------- --------- --------- --------- (IN MILLIONS) Change in benefit obligation: Benefit obligation as of January 1 $ 3,547.9 $ 1,506.1 $ 1,581.6 $ 752.0 Service cost 58.8 34.9 28.5 18.3 Interest cost 249.3 133.3 113.6 64.4 Plan amendments -- 3.6 (121.1) -- Actuarial loss 268.0 123.1 440.4 73.3 Voluntary early retirement program -- -- -- 2.3 GPU acquisition (Note 12) (11.8) 1,878.3 110.0 716.9 Benefits paid (245.8) (131.4) (83.0) (45.6) --------- --------- --------- --------- Benefit obligation as of December 31 3,866.4 3,547.9 2,070.0 1,581.6 --------- --------- --------- --------- Change in fair value of plan assets: Fair value of plan assets as of January 1 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets (348.9) 8.1 (57.1) 12.7 Company contribution -- -- 37.9 43.3 GPU acquisition -- 1,901.0 -- 462.0 Benefits paid (245.8) (131.4) (42.5) (6.0) --------- --------- --------- --------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 --------- --------- --------- --------- Funded status of plan (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation -- -- 92.4 101.6 --------- --------- --------- --------- Net amount recognized $ 286.9 $ 246.5 $ (859.5) $ (714.5) ========= ========= ========= ========= Consolidated Balance Sheets classification: Prepaid (accrued) benefit cost $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset 78.5 -- -- -- Accumulated other comprehensive loss 757.0 -- -- -- --------- --------- --------- --------- Net amount recognized $ 286.9 $ 246.5 $ (859.5) $ (714.5) ========= ========= ========= ========= Assumptions used as of December 31: Discount rate 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets 9.00% 10.25% 9.00% 10.25% Rate of compensation increase 3.50% 4.00% 3.50% 4.00%
Net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:
OTHER PENSION BENEFITS POSTRETIREMENT BENEFITS ------------------------ ------------------------ 2002 2001 2000 2002 2001 2000 ------ ------ ------ ------ ------ ------ (IN MILLIONS) Service cost $ 58.8 $ 34.9 $ 27.4 $ 28.5 $ 18.3 $ 11.3 Interest cost 249.3 133.3 104.8 113.6 64.4 45.7 Expected return on plan assets (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) Amortization of transition obligation (asset) -- (2.1) (7.9) 9.2 9.2 9.2 Amortization of prior service cost 9.3 8.8 5.7 3.2 3.2 3.2 Recognized net actuarial loss (gain) -- -- (9.1) 11.2 4.9 -- Voluntary early retirement program -- 6.1 17.2 -- 2.3 -- ------ ------ ------ ------ ------ ------ Net periodic benefit cost (income) $(28.7) $(23.8) $(42.9) $114.0 $ 92.4 $ 68.9 ====== ====== ====== ====== ====== ======
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. (J) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. As of December 31, 2002, cash and cash equivalents included $50 million used for the redemption of long-term debt in January 2003. Noncash financing and investing activities included the 2001 FirstEnergy common stock issuance of $2.6 billion for the GPU acquisition and capital lease transactions amounting to $3.1 million and $89.3 million for the years 2001 and 2000, 52 respectively. There were no capital lease transactions in 2002. Commercial paper transactions of OES Fuel, Incorporated (a wholly owned subsidiary of OE) that had initial maturity periods of three months or less were reported net within financing activities under long-term debt, prior to the expiration of the related long-term financing agreement in March 2002, and were reflected as currently payable long-term debt on the Consolidated Balance Sheet as of December 31, 2001. Net losses on foreign currency exchange transactions reflected in FirstEnergy's 2002 Consolidated Statement of Income consisted of approximately $104.1 million from FirstEnergy's Argentina operations (see Note 3 - Divestitures). In the Consolidated Statements of Cash Flows, the amounts included in "Cash investments" under Net cash used for Investing Activities primarily consist of changes in capital trust investments of $(87) million (see Note 4 - Leases) and other cash investments of $6 million. The amounts included in "Other amortization, net" under Net cash provided from Operating Activities primarily consist of amounts from the reduction of an electric service obligation under a CEI electric service prepayment program. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31:
2002 2001 ------------------- ------------------- CARRYING FAIR CARRYING FAIR VALUE VALUE VALUE VALUE -------- -------- -------- -------- (IN MILLIONS) Long-term debt* $ 12,465 $ 12,761 $ 12,897 $ 13,097 Preferred stock $ 445 $ 454 $ 636 $ 626 Investments other than cash and cash equivalents: Debt securities: - Maturity (5-10 years) $ 502 $ 471 $ 439 $ 402 - Maturity (more than 10 years) 927 1,030 990 1,009 Equity securities 15 15 15 15 All other 1,668 1,669 1,730 1,734 -------- -------- -------- -------- $ 3,112 $ 3,185 $ 3,174 $ 3,160 ======== ======== ======== ========
* Excluding approximately $1.75 billion of long-term debt in 2001 related to pending divestitures. The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Companies' ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Companies have no securities held for trading purposes. See Note 9 - Other Information for discussion of SFAS 115 activity related to equity investments. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. In conjunction with the adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were reclassified to OCI in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized gains (losses) were approximately $(15.6) million and interest and dividend income totaled approximately $33.2 million. On January 1, 2001, FirstEnergy adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133". The cumulative effect to January 1, 2001 was a charge of $8.5 million (net of $5.8 million of income taxes) or $.03 per share of common stock. The reported results of operations for the year ended December 31, 2000 would not have been materially different if this accounting had been in effect during that year. 53 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. The impact of ineffectiveness on earnings during 2002 was not material. 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 $110.2 million included in Accumulated Other Comprehensive Loss (AOCL) as of December 31, 2002, for derivative hedging activity, as compared to the December 31, 2001 balance of $169.4 million in net deferred losses, resulted from the reversal of $6.0 million of derivative losses related to the sale of Avon, a $33.0 million reduction related to current hedging activity and a $20.2 million reduction due to net hedge gains included in earnings during the year. Approximately $19.0 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 from 16% to approximately 20% at year end. 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. After reaching a maximum notional position of $993.5 million in the third quarter of 2002, FirstEnergy unwound $400 million of these swaps in the fourth quarter of 2002 during a period of steadily declining market interest rates. Gains recognized from unwinding these swaps were added to the carrying value of the hedged debt and will be recognized over the remaining life of the underlying debt (through November 2006). 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. (K) REGULATORY ASSETS- The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations. OE and Penn recognized additional cost recovery of $270 million in 2000 as additional regulatory asset amortization in accordance with their prior Ohio and current Pennsylvania regulatory plans. 54 Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
2002 2001 -------- -------- RESTATED (SEE NOTE 2(M)) (IN MILLIONS) Regulatory transition charge $7,795.7 $7,751.5 Customer receivables for future income taxes 394.0 433.0 Societal benefits charge 143.8 166.6 Loss on reacquired debt 73.7 80.0 Employee postretirement benefit costs 87.7 98.6 Nuclear decommissioning, decontamination and spent fuel disposal costs 98.8 80.2 Provider of last resort costs -- 116.2 Property losses and unrecovered plant costs 87.8 104.1 Other 71.9 82.4 -------- -------- Total $8,753.4 $8,912.6 -------- --------
(L) CHANGE IN INCOME STATEMENT CLASSIFICATIONS - FirstEnergy recorded a net charge to income during the year ended December 31, 2002 of $57.1 million (net of income taxes of $13.6 million) relative to decisions to retain interests in the Avon and Emdersa businesses previously classified as held for sale - see Note 3. This net charge represents the aggregate results of operations of Avon and Emdersa for the respective periods these businesses were held for sale. This charge was previously reported on the Consolidated Statement of Income as cumulative effect of a change in accounting. In April 2003 it was determined that charge should instead have been classified in operations. As further, discussed in Note 3, the decision to retain Avon and Emdersa were made in the first and fourth quarters, respectively, of the year ended 2002. The results of operations for these businesses for the quarters in which the decisions were made to retain them have been classified in their respective revenue and expense captions on the Consolidated Statement of Income for the year ended December 31, 2002. The aggregate results of operations for periods preceding the periods in which the decision was made to retain Emdersa has been recorded net on the Consolidated Statement of Income as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale. 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 year ended December 31, 2002 are as follows:
AS PREVIOUSLY REVISED PRESENTED PRESENTATION* ------------- ------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues $ 12,151,997 $ 12,247,401 Expenses 9,969,814 9,995,740 Cumulative adjustment for retained businesses previously held for sale -- (93,723) ------------- ------------- Income before interest and income taxes 2,182,183 2,157,938 Net interest charges 946,306 965,582 Income taxes 549,476 563,076 Income before cumulative effect of accounting change 686,401 629,280 Cumulative effect of accounting change (57,121) -- ------------- ------------- Net income $ 629,280 $ 629,280 ------------- ------------- Basic Earnings Per Share: Income before cumulative effect of accounting change $ 2.34 $ 2.15 Cumulative effect of accounting change (0.19) -- ------------- ------------- Net income $ 2.15 $ 2.15 ============= ============= Diluted Earnings Per Share: Income before cumulative effect of accounting change $ 2.33 $ 2.14 Cumulative effect of accounting change (0.19) -- ------------- ------------- Net income $ 2.14 $ 2.14 ============= =============
* Revised as discussed above and filed on Form 10-K/A Amendment No. 1. Excludes effect of restatements discussed in note 1(M) below. (M) RESTATEMENTS The Company is restating its financial statements for the year ended December 31, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial adjustments related to the recognition of a valuation allowance on a tax benefit recognized in 2002 and other adjustments are now reflected in results for the year ended December 31, 2002. 55 Transition Cost Amortization - As discussed above under Regulatory Matters in Note 2(D), 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, but not in the financial statements prepared under GAAP. The Ohio companies 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 previously recorded regulatory assets recovered under the transition plan through the end of 2009. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of APB 16. In connection with the reassessment of the accounting for the Transition Plan, the Company 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, the Company 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 because 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 liability for the Bruce Mansfield Plant was recorded as a regulatory asset since regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the Company's regulatory plan in effect at the time of the merger and subsequently under the transition plan. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $37 million per year). 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 $755 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $48 million per year). Before the start of the Transition Plan in fiscal 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 - 2009 for CEI and 2007 for TE. FirstEnergy has reflected the net impact of the accounting for these items for the period from the merger in 1997 through 2001 in the 2002 financial statements. The cumulative impact to net income recorded in 2002 related to these prior periods increased net income by $5.9 million in the restated 2002 financial statements and is reflected as a reduction in other operating expenses in the accompanying consolidated statement of income. In addition, the impact increased the following balances in the consolidated balance sheet as of January 1, 2002:
INCREASE (DECREASE) (IN THOUSANDS) Goodwill............................ $ 381,780 Regulatory assets................... 636,100 ----------- Total assets........................ $1,017,880 ========== Other current liabilities........... 84,600 Deferred income taxes............... (262,580) Deferred investment tax credits..... (828) Other deferred credits.............. 1,190,800 ----------- Total liabilities................... $1,011,992 ==========
The adjustments were not reflected in the periods prior to the year ended December 31, 2002 as the impact was not material. 56 The after-tax effect of the actual 2002 impact of these items decreased net income for the year ended December 31, 2002, by $71 million, or $0.24 per share. The adjustments described above are anticipated to result in a decrease in reported net income through 2005 and an increase in net income for the period 2006 through 2017, the end of the lease term for Beaver Valley Unit 2. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2009 (in millions). 2003 $685 2004 786 2005 913 2006 378 2007 213 2008 163 2009 44
DISCONTINUED OPERATIONS - On April 18, 2003, FirstEnergy divested its ownership in 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. As a result of the abandonment, FirstEnergy recorded a $67.4 million change in the second quarter 2003. As a result of FirstEnergy's divestiture of its ownership in Emdersa in April 2003, FirstEnergy has reflected the results of this business during 2002 as a discontinued operation in the restated year ended December 31, 2002 Consolidated Statement of Income as "Discontinued Operations". There was no impact on the year ended December 31, 2001 Consolidated Statement of Income as Emdersa was reported as an asset held for sale during this period. The following table summarizes Emdersa's major assets and liabilities included in FirstEnergy's Consolidated Balance Sheet as of December 31, 2002. The amounts have not been reflected separately in the accompanying balance sheets as the amounts are not significant to the Consolidated Balance Sheet. (in thousands) -------------- Assets Abandoned: Current assets $ 17,344 Property, plant and equipment 61,980 Other 8,737 -------- Total Assets $ 88,061 ======== Liabilities Related to Assets Abandoned: Current liabilities $ 12,777 Long-term debt 100,202 Other 10,548 -------- Total Liabilities $123,527 ========
OTHER ADJUSTMENTS - 57 The Company has included in this restatement certain immaterial adjustments that were not previously recognized in 2002 related to the recognition of a valuation allowance on a tax benefit recognized in 2002 and other adjustments. The impact of these adjustments decreased net income by $11.3 million The effects of all of these adjustments on the Consolidated Statement of Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows previously reported, and revised per Note 3(L) above, for December 31, 2002 are as follows:
TRANSITION ABOVE AS PREVIOUSLY COST MARKET DISCONTINUED AS REPORTED AMORTIZATION LEASES OPERATIONS OTHER RESTATED -------- ------------ ------ ---------- ----- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) CONSOLIDATED STATEMENT OF INCOME REVENUES: Electric utilities $ 9,165,805 $ -- $ -- $ -- $ -- $ 9,165,805 Unregulated businesses 3,081,596 -- -- (16,875) -- 3,064,721 ------------ ------------ ------------ ------------ ------------ ------------ Total revenues 12,247,401 -- -- (16,875) -- 12,230,526 ------------ ------------ ------------ ------------ ------------ ------------- EXPENSES: Fuel and purchased power 3,673,610 -- -- -- (10,700) 3,662,910 Purchased gas 592,116 -- -- -- -- 592,116 Other operating expenses 3,973,781 -- (90,688) (8,984) 14,800 3,888,909 Provision for depreciation and amortization 1,105,904 150,474 50,272 (807) -- 1,305,843 General taxes 650,329 -- -- -- -- 650,329 ------------ ------------ ------------ ------------ ------------ ------------- Total expenses 9,995,740 150,474 (40,416) (9,791) 4,100 10,100,107 ------------ ------------ ------------ ------------ ------------ ------------- CUMULATIVE ADJUSTMENT FOR RETAINED BUSINESSES PREVIOUSLY HELD FOR SALE (NOTE 2L) (93,723) -- -- 93,723 -- -- ------------ ------------ ------------ ------------ ------------ ------------- INCOME BEFORE INTEREST AND INCOME TAXES 2,157,938 (150,474) 40,416 86,639 (4,100) 2,130,419 ------------ ------------ ------------ ------------ ------------ ------------ NET INTEREST CHARGES: Interest expense 911,109 -- -- (837) -- 910,272 Capitalized interest (24,474) -- -- -- -- (24,474) Subsidiaries' preferred stock dividends 78,947 -- -- -- (3,300) 75,647 ------------ ------------ ------------ ------------ ------------ ------------- Net interest charges 965,582 -- -- (837) (3,300) 961,445 ------------ ------------ ------------ ------------ ------------ ------------- INCOME TAXES 563,076 (30,920) (13,962) -- 10,500 528,694 ------------ ------------ ------------ ------------ ------------ ------------ INCOME BEFORE DISCONTINUED OPERATIONS 629,280 (119,554) 54,378 87,476 (11,300) 640,280 DISCONTINUED OPERATIONS -- -- -- (87,476) -- (87,476) ------------ ------------ ------------ ------------ ------------ ------------- NET INCOME $ 629,280 $ (119,554) $ 54,378 -- $ (11,300) $ 552,804 ============ ============ ============ ============ ============ ============ BASIC EARNINGS PER SHARE OF COMMON STOCK $ 2.15 $ (0.41) $ 0.19 -- $(0.04) $ 1.89 DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 2.14 $ (0.41) $ 0.19 -- $(0.04) $ 1.88
58
TRANSITION ABOVE AS PREVIOUSLY COST MARKET AS REPORTED AMORTIZATION LEASES OTHER RESTATED -------- ------------ ----------- ----- -------- (IN THOUSANDS) CONSOLIDATED BALANCE SHEET ASSETS CURRENT ASSETS: Cash and cash equivalents $ 196,301 $ -- $ -- $ -- $ 196,301 Receivables - Customers 1,153,486 -- -- -- 1,153,486 Other 473,106 -- -- (3,500) 469,606 Materials and supplies, at average cost Owned 253,047 -- -- -- 253,047 Under consignment 174,028 -- -- -- 174,028 Prepayments and other 203,630 -- -- -- 203,630 ------------ ------------ ------------ ------------ ------------ 2,453,598 -- -- (3,500) 2,450,098 ------------ ------------ ------------ ------------ ------------ PROPERTY, PLANT AND EQUIPMENT: In service 20,372,224 -- -- -- 20,372,224 Less--Accumulated provision for depreciation 8,551,427 -- -- 1,500 8,552,927 ------------ ------------ ------------ ------------ ------------ 11,820,797 -- -- (1,500) 11,819,297 Construction work in progress 859,016 -- -- 859,016 ------------ ------------ ------------ ------------ ------------ 12,679,813 -- -- (1,500) 12,678,313 ------------ ------------ ------------ ------------ ------------ INVESTMENTS: Capital trust investments (Note 4) 1,079,435 -- -- -- 1,079,435 Nuclear plant decommissioning trusts 1,049,560 -- -- -- 1,049,560 Letter of credit collateralization (Note 4) 277,763 -- -- -- 277,763 Other 918,874 -- -- -- 918,874 ------------ ------------ ------------ ------------ ------------ 3,325,632 -- 3,325,632 ------------ ------------ ------------ ------------ ------------ DEFERRED CHARGES: Regulatory assets 8,323,001 (154,600) 585,000 -- 8,753,401 Goodwill 5,896,292 -- 381,780 -- 6,278,072 Other (Note 2I) 902,437 -- -- (1,600) 900,837 ------------ ------------ ------------ ------------ ------------ 15,121,730 -- -- (1,600) 15,932,310 ------------ ------------ ------------ ------------ ------------ $ 33,580,773 $ (154,600) $ 466,780 $ (6,600) $ 34,386,353 ============ ============ ============ ============ ============ LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt and preferred stock $ 1,702,822 $ -- $ -- $ -- $ 1,702,822 Short-term borrowings (Note 6) 1,092,817 -- -- -- 1,092,817 Accounts payable 918,268 -- -- (11,800) 906,468 Accrued taxes 456,178 -- -- (1,057) 455,121 Other 1,000,415 -- 84,600 8,800 1,093,815 ------------ ------------ ------------ ------------ ------------ 5,170,500 -- 84,600 (4,057) 5,251,043 ------------ ------------ ------------ ------------ ------------ CAPITALIZATION Common stockholders' equity(a) 7,120,049 (123,680) 58,504 (4,212) 7,050,661 Preferred stock of consolidated subsidiaries -- Not subject to mandatory redemption 335,123 -- -- -- 335,123 Subject to mandatory redemption 18,521 -- -- -- 18,521 Subsidiary-obligated mandatorily redeemable preferred securities (Note 5F) 409,867 -- -- -- 409,867 Long-term debt 10,872,216 -- -- -- 10,872,216 ------------ ------------ ------------ ------------ ------------ 18,755,776 (123,680) 58,504 (4,212) 18,686,388 ------------ ------------ ------------ ------------ ------------ DEFERRED CREDITS: Accumulated deferred income taxes 2,367,997 (31,346) (282,324) 15,355 2,069,682 Accumulated deferred investment tax credits 235,758 426 -- -- 236,184 Nuclear plant decommissioning costs 1,254,344 -- -- (10,786) 1,243,558 Power purchase contract loss liability 3,136,538 -- -- -- 3,136,538 Retirement benefits 1,564,930 -- -- -- 1,564,930 Other 1,094,930 -- 1,106,000 (2,900) 2,198,030 ------------ ------------ ------------ ------------ ------------ 9,654,497 (30,920) 823,676 1,669 10,448,922 ------------ ------------ ------------ ------------ ------------ COMMITMENTS, GUARANTEES AND CONTINGENCIES $ 33,580,773 $ (154,600) $ 966,780 $ (6,600) $ 34,386,353 ============ ============ ============ ============ ============
(a) Other adjustments include an impact to other comprehensive income. 60
TRANSITION AS PREVIOUSLY COST LEASE DISCONTINUED AS REPORTED AMORTIZATION OBLIGATIONS OPERATIONS OTHER RESTATED ----------- ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS) CONSOLIDATED STATEMENT OF CASH FLOWS CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 629,280 $ (119,554) $ 54,378 $ -- $ (11,300) $ 552,804 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 1,105,904 150,474 50,272 (807) -- 1,305,843 Nuclear fuel and lease amortization 80,507 -- -- -- -- 80,507 Other amortization, net (Note 2) (16,593) -- -- -- -- (16,593) Deferred costs recoverable as regulatory assets (362,956) -- -- -- -- (362,956) Avon investment impairment (Note 3) 50,000 -- -- -- -- 50,000 Deferred income taxes, net 89,860 (29,666) (13,962) -- 10,500 56,732 Investment tax credits, net (27,071) (1,254) -- -- -- (28,325) Cumulative adjustment (see Note 2 (L)) 93,723 -- -- (93,723) -- -- Discontinued operations (see Note (M)) -- -- -- 87,476 -- 87,476 Receivables (85,307) -- -- -- -- (85,307) Materials and supplies (29,557) -- -- -- -- (29,557) Accounts payable 220,762 -- -- -- -- 220,762 Deferred lease costs -- -- (84,800) -- -- (84,800) Other (Note 9) 166,735 -- (5,888) 7,054 800 168,701 ----------- ----------- ----------- ----------- ----------- ----------- Net cash provided from operating activities 1,915,287 -- -- -- -- 1,915,287 ----------- ----------- ----------- ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Net cash provided from (used for) financing activities (1,123,469) -- -- -- -- (1,123,469) ----------- ----------- ----------- ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Net cash provided from (used for) investing activities (815,695) -- -- -- -- (815,695) ----------- ----------- ----------- ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents (23,877) -- -- -- -- (23,877) Cash and cash equivalents at beginning of year 220,178 -- -- -- -- 220,178 ----------- ----------- ----------- ----------- ----------- ----------- Cash and cash equivalents at end of year $ 196,301 $ -- $ -- -- $ -- $ 196,301 =========== =========== =========== =========== =========== ===========
3. DIVESTITURES: INTERNATIONAL OPERATIONS- FirstEnergy 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 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 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 Statements of Income. Additionally, assets and liabilities of these international operations were 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 Energy Partners Holdings (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 purchase price and reversal of the effects of Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the year ended 61 December 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 2(L) 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 its Argentina operations, GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (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 include 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 and Emdersa's results of operations were included in FirstEnergy's 2002 Consolidated Statement of Income. 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). See Note 2(L) for the effects of the change in classification and Note 2(M) for discontinued operations treatment. On October 1, 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 recognized a currency translation adjustment in other comprehensive income 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. SALE OF GENERATING ASSETS- In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 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. LEASES: The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated, a wholly owned subsidiary of OE, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits of approximately $278 million pledged to the financial institution providing those letters of credit are the sole property of OES Finance and are investments which are classified as "Held to Maturity". In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to OE as sole owner of OES Finance common stock. 62 Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2002, are summarized as follows:
2002 2001 2000 ------- ------- ------- (IN MILLIONS) Operating leases Interest element $ 188.4 $ 194.1 $ 202.4 Other 135.9 120.5 111.1 Capital leases Interest element 2.4 8.0 12.3 Other 2.5 35.5 64.2 ------- ------- ------- Total rentals $ 329.2 $ 358.1 $ 390.0 ======= ======= =======
The future minimum lease payments as of December 31, 2002, are:
OPERATING LEASES ------------------------------------ CAPITAL LEASE CAPITAL LEASES PAYMENTS TRUSTS NET -------- -------- -------- -------- (IN MILLIONS) 2003 $ 4.6 $ 331.9 $ 178.8 $ 153.1 2004 6.0 293.8 111.8 182.0 2005 5.4 313.4 130.3 183.1 2006 5.4 322.0 141.8 180.2 2007 1.8 299.5 130.7 168.8 Years thereafter 8.0 2,807.9 977.7 1,830.2 -------- -------- -------- -------- Total minimum lease payments 31.2 $4,368.5 $1,671.1 $2,697.4 ======== ======== ======== Executory costs 7.1 -------- Net minimum lease payments 24.1 Interest portion 8.3 -------- Present value of net minimum lease payments 15.8 Less current portion 1.8 -------- Noncurrent portion $ 14.0 --------
OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport capital trust arrangements effectively reduce lease costs related to those transactions. 5. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on FirstEnergy's common stock. (B) EMPLOYEE STOCK OWNERSHIP PLAN- An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2002, 2001 and 2000, 1,151,106 shares, 834,657 shares and 826,873 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 3,966,269 shares unallocated as of December 31, 2002, was approximately $130.8 million. Total ESOP-related compensation expense was calculated as follows:
2002 2001 2000 (IN MILLIONS) ----------------------------------------------------------------------------------------------------- Base compensation $34.2 $25.1 $18.7 Dividends on common stock held by the ESOP and used to service debt (7.8) (6.1) (6.4) ----------------------------------------------------------------------------------------------------- Net expense $26.4 $19.0 $12.3 =====================================================================================================
(C) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock-based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000 ------------------------------------------------------------------------------------ Restricted common shares granted 36,922 133,162 208,400 Weighted average market price $36.04 $35.68 $26.63 Weighted average vesting period (years) 3.2 3.7 3.8 Dividends restricted Yes * Yes ------------------------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. See Note 9 - Other Information for discussion of stock-based employee compensation expense recognized for restricted stock and EDCP stock units. 64 Stock option activities under the FE Programs for the past three years were as follows:
NUMBER OF WEIGHTED AVERAGE STOCK OPTION ACTIVITIES OPTIONS EXERCISE PRICE --------------------------------------------------------------------------------------- Balance, January 1, 2000 2,153,369 $25.32 (159,755 options exercisable) 24.87 Options granted 3,011,584 23.24 Options exercised 90,491 26.00 Options forfeited 52,600 22.20 Balance, December 31, 2000 5,021,862 24.09 (473,314 options exercisable) 24.11 Options granted 4,240,273 28.11 Options exercised 694,403 24.24 Options forfeited 120,044 28.07 Balance, December 31, 2001 8,447,688 26.04 (1,828,341 options exercisable) 24.83 Options granted 3,399,579 34.48 Options exercised 1,018,852 23.56 Options forfeited 392,929 28.19 Balance, December 31, 2002 10,435,486 28.95 (1,400,206 options exercisable) 26.07
As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 2G - Stock-Based Compensation. (D) PREFERRED AND PREFERENCE STOCK- Penn's 7.75% series has a restriction which prevents early redemption prior to July 2003. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice. Met-Ed's and Penelec's preferred stock authorization consists of 10 million and 11.435 million shares, respectively, without par value. No preferred shares are currently outstanding for the two companies. The Companies' preference stock authorization consists of 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding. (E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Annual sinking fund provisions for the Companies' preferred stock are as follows:
REDEMPTION PRICE PER SERIES SHARES SHARE ----------------------------------------------------------------------------- CEI $ 7.35C 10,000 $ 100 Penn 7.625% 7,500 100 -----------------------------------------------------------------------------
Annual sinking fund requirements for the next five years are $1.8 million in each year 2003 through 2006 and $12.3 million in 2007. (F) SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED DEBENTURES OF SUBSIDIARIES- CEI formed a statutory business trust as a wholly owned financing subsidiary. The trust sold preferred securities and invested the gross proceeds in the 9.00% subordinated debentures of CEI and the sole assets of the trust are the applicable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. 65 Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. CEI has effectively provided a full and unconditional guarantee of payments due on its trust's preferred securities. Its trust preferred securities are redeemable at 100% of their principal amount at CEI's option beginning in December 2006. Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions as CEI. However, 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, each trust invested the gross proceeds from the sale of its trust preferred securities in the preferred securities of the applicable limited partnership, which in turn invested those proceeds in the 7.35% and 7.34% subordinated debentures of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of its obligations under its trust's preferred securities. The Met-Ed and Penelec trust preferred securities are redeemable at the option of Met-Ed and Penelec beginning in May 2004 and September 2004, respectively, at 100% of their principal amount. JCP&L formed a limited partnership for a substantially similar transaction; however, no statutory trust is involved. That limited partnership, of which JCP&L is the sole general partner, invested the gross proceeds from the sale of its monthly income preferred securities (MIPS) in JCP&L's 8.56% subordinated debentures. JCP&L has effectively provided a full and unconditional guarantee of its obligations under the limited partnership's MIPS. The limited partnership's MIPS are redeemable at JCP&L's option at 100% of their principal amount. In each of these transactions, interest on the subordinated debentures (and therefore the distributions on trust preferred securities or MIPS) may be deferred for up to 60 months, but the parent company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. The following table lists the subsidiary trusts and limited partnership and information regarding their preferred securities outstanding as of December 31, 2002:
STATED SUBORDINATED MATURITY RATE VALUE(A) DEBENTURES ----------------------------------------------------------------------------------------------------- (IN MILLIONS) Cleveland Electric Financing Trust (b) 2031 9.00% $100.0 $103.1 Met-Ed Capital Trust (c) 2039 7.35% $100.0 $103.1 Penelec Capital Trust (c) 2039 7.34% $100.0 $103.1 JCP&L, Capital L.P. (b) 2044 8.56% $125.0 $128.9 -----------------------------------------------------------------------------------------------------
(a) The liquidation value is $25 per security. (b) The sole assets of the trust or limited partnership are the parent company's subordinated debentures with the same rate and maturity date as the preferred securities. (c) The sole assets of the trust are the preferred securities of Met-Ed Capital II, L.P. and Penelec Capital II, L.P., respectively, whose sole assets are the parent company's subordinated debentures with the same rate and maturity date as the preferred securities. (G) LONG-TERM DEBT- Each of the Companies has a first mortgage indenture under which it issues from time to time first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. The nonpayments debt covenant which could trigger a default is applicable to financing arrangements of FirstEnergy and all of the Companies. The maintenance of minimum fixed charge ratios and debt to capitalization ratios covenants is applicable to financing arrangements of FirstEnergy, the Ohio Companies and Penn. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Companies. Based on the amount of bonds authenticated by the respective mortgage bond trustees through December 31, 2002, the Companies' annual improvement fund requirements for all bonds issued under the various mortgage indentures of the Companies amounts to $61.5 million. OE and Penn expect to deposit funds with their respective mortgage bond trustees in 2003 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec expect to fulfill their sinking and improvement fund obligation by providing bondable property additions and/or retired bonds to the respective mortgage bond trustees. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: 66
(IN MILLIONS) ------------ 2003 $1,698.8 2004 1,603.8 2005 918.5 2006 1,402.2 2007 251.9 -----------
Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $626 million, $266 million and $47 million in 2003, 2004 and 2005, respectively, which represents the next date at which the debt holders may exercise this provision. The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $287.6 million and noncancelable municipal bond insurance policies of $544.1 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.00% to 1.375% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. FirstEnergy had unsecured borrowings of $395 million as of December 31, 2002, under its $500 million long-term revolving credit facility agreement which expires November 29, 2004. FirstEnergy currently pays an annual facility fee of 0.25% on the total credit facility amount. The fee is subject to change based on changes to FirstEnergy's credit ratings. CEI and TE have unsecured letters of credit of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. CEI and TE are jointly and severally liable for the letters of credit. In connection with its Beaver Valley Unit 2 sale and leaseback arrangements, OE has similar letters of credit secured by deposits held by its subsidiary, OES Finance (see Note 4). (H) SECURITIZED TRANSITION BONDS- On June 11, 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 nor did it purchase any of the transition bonds, which are included in long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. 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. (I) 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 December 31, 2002, accumulated other comprehensive income (loss) consisted of a minimum liability for unfunded retirement benefits of $450.2 million, unrealized losses on investments in securities available for sale of $4.3 million, unrealized losses on derivative instrument hedges of $110.2 million and unrealized currency translation adjustments of $91.4 million. See Note 9 - Other Information for discussion of derivative instruments reclassifications to net income. (J) STOCK REPURCHASE PROGRAM- The Board of Directors authorized the repurchase of up to 15 million shares of FirstEnergy's common stock over a three-year period beginning in 1999. Repurchases were made on the open market, at prevailing prices, and were funded primarily through the use of operating cash flows. During 2001 and 2000, FirstEnergy repurchased and retired 550,000 shares (average price of $27.82 per share), and 7.9 million shares (average price of $24.51 per share), respectively. 67 6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding as of December 31, 2002, consisted of $933.1 million of bank borrowings and $159.7 million of OES Capital, Incorporated commercial paper. OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expires in August 2003. FirstEnergy and its subsidiaries have various credit facilities (including a FirstEnergy $1 billion short-term revolving credit facility) with domestic and foreign banks that provide for borrowings of up to $1.084 billion under various interest rate options. To assure the availability of these lines, FirstEnergy and its subsidiaries are required to pay annual commitment fees that vary from 0.125% to 0.20%. These lines expire at various times during 2003. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2002 and 2001, were 2.41% and 3.80%, respectively. 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- FirstEnergy's current forecast reflects expenditures of approximately $3.1 billion for property additions and improvements from 2003-2007, of which approximately $727 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $485 million, of which approximately $69 million applies to 2003. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $483 million and $88 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retrospective rating plan would be $352.4 million per incident but not more than $40 million in any one year for each incident. The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. The Companies have also obtained approximately $1.2 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $68.4 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. (C) 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 rating-contingent collateralization provisions. As of December 31, 2002, outstanding guarantees and other assurances aggregated $913 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 $856 million as of December 31, 2002 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts is remote. 68 Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $26 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 December 31, 2002, rating-contingent collateralization totaled $31 million. (D) 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 oxide (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 on February 3, 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 69 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 December 31, 2002, 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 its SBC. The Companies have total accrued liabilities aggregating approximately $54.3 million as of December 31, 2002. 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. (E) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims for personal injury, asbestos and property damage and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant are described below. TMI-2 was acquired by FirstEnergy in 2001 as part of the merger with GPU. As a result of the 1979 TMI-2 accident, claims for alleged personal injury against JCP&L, Met-Ed, Penelec and GPU had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by GPU and dismissed the ten initial "test cases" which had been selected for a test case trial. On January 15, 2002, the District Court granted GPU's July 2001 motion for summary judgment on the remaining 2,100 pending claims. On February 14, 2002, plaintiffs filed a notice of appeal to the United States Court of Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to hear the appeal which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory. In May 2001, the court denied without prejudice the defendants' motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that JCP&L is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. JCP&L has also filed a motion for partial summary judgment that is currently pending before the Superior Court. FirstEnergy is unable to predict the outcome of these matters. (F) OTHER COMMITMENTS AND CONTINGENCIES- GPU made significant investments in foreign businesses and facilities through its GPU Capital and GPU Power subsidiaries. Although FirstEnergy will attempt 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, under certain circumstances, to make additional standby equity contributions of $21.3 million, which FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA project is $254 million as of December 31, 2002. The lenders include the Overseas Private Investment Corporation, US Export Import Bank and a commercial bank syndicate. FirstEnergy has 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. 70 8. 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 2001 "Other" assets amount included assets in the United Kingdom identified for divestiture (see Note 3 - Divestitures) which were sold in 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 a competing generation supplier. The regulated services segment obtains a portion of its required generation through power supply agreements with the competitive services segment. The competitive services segment includes all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of commodity requirements, as well as other competitive energy-application services. Competitive products are increasingly marketed to customers as bundled services. Segment financial data in 2001 and 2000 have been reclassified to conform with the current year business segment organizations and operations. Changes in the current year methodology for computing revenues and expenses used in management reporting for the Competitive Services segment have been reflected in reclassified 2001 and 2000 financial results. Methodology changes included using a fixed rate revenues calculation for the Competitive Services segment's power sales agreement with the Regulated Services segment. This change, when applied to previously reported results, caused lower revenues, income taxes and net income as compared to prior calculated amounts and, correspondingly, reduced purchased power expenses and increased income taxes and net income for the Regulated Services segment. Financial data for these business segments are as follows: 71 SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING SERVICES SERVICES OTHER(C) ADJUSTMENTS CONSOLIDATED (C) -------- -------- -------- ----------- ---------------- (IN MILLIONS) 2002 External revenues $ 8,794 $3,015 $409 $ 13 (a) $ 12,231 Internal revenues 1,052 1,666 478 (3,196) (b) -- Total revenues 9,846 4,681 887 (3,183) 12,231 Depreciation and amortization 1,235 30 41 -- 1,306 Net interest charges 587 46 386 (58) (b) 961 Income taxes 698 (87) (82) -- 529 Income before discontinued operations 938 (119) (179) -- 640 Discontinued operations -- -- (87) -- (87) Net income 927 (108) (266) -- 553 Total assets 30,494 2,281 1,611 -- 34,386 Total goodwill 5,993 285 -- -- 6,278 Property additions 490 403 105 -- 998 2001 External revenues $ 5,729 $2,165 $ 11 $ 94 (a) $ 7,999 Internal revenues 1,645 1,846 350 (3,841) (b) -- Total revenues 7,374 4,011 361 (3,747) 7,999 Depreciation and amortization 841 21 28 -- 890 Net interest charges 571 25 74 (114) (b) 556 Income taxes 537 (23) (40) -- 474 Income before cumulative effect of a change in accounting 729 (23) (51) -- 655 Net income 729 (32) (51) -- 646 Total assets 28,054 2,981 6,317 -- 37,352 Total goodwill 5,325 276 -- -- 5,601 Property additions 447 375 30 -- 852 2000 External revenues $ 5,415 $1,545 $ 1 $ 68 (a) $ 7,029 Internal revenues 1,222 2,114 306 (3,642) (b) -- Total revenues 6,637 3,659 307 (3,574) 7,029 Depreciation and amortization 919 13 2 -- 934 Net interest charges 558 10 19 (58) (b) 529 Income taxes 365 27 (15) -- 377 Net income 563 39 (3) -- 599 Total assets 14,682 2,685 574 -- 17,941 Total goodwill 1,867 222 -- -- 2,089 Property additions 422 126 40 -- 588
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) Restated - See Notes 2L and 2M. PRODUCTS AND SERVICES
ENERGY RELATED ELECTRICITY OIL & GAS SALES AND YEAR SALES SALES SERVICES ---- ----- ----- -------- (IN MILLIONS) 2002 $9,697 $620 $1,052 2001 6,078 792 693 2000 5,537 582 563
2002 2001 -------------------------------- ------------------------------- GEOGRAPHIC INFORMATION REVENUES ASSETS REVENUES ASSETS ---------------------- -------- ------ -------- ------ (IN MILLIONS) United States $11,908 $33,628 $7,991 $32,187 Foreign countries* 339 758 8 5,165 ---------- ---------- ---------- -------- Total $12,247 $34,386 $7,999 $37,352 ========== ========== ========== ========
* See Note 3 for discussion of future divestitures of international operations and Note 2L for discussion of revised financial data. 72 9. OTHER INFORMATION: The following financial data provides supplemental unaudited information to the consolidated financial statements and notes previously reported in 2001 and 2000: (A) CONSOLIDATED STATEMENTS OF CASH FLOWS
2002 2001 2000 ---- ---- ---- RESTATED (IN THOUSANDS) Other Cash Flows From Operating Activities: Accrued taxes $ 36,566 $ 8,915 $ (84) Accrued interest (26,281) 117,520 (8,853) Retail rate refund obligation payments (43,016) -- -- Interest rate hedge -- (132,376) -- Prepayments and other 132,980 (146,741) (21,975) All other 68,452 (97,882) 76,441 --------- --------- --------- Total-Other $ 168,701 $(250,564) $ 45,529 ========= ========= ========= Other Cash Flows from Investing Activities: Retirements and transfers $ 29,619 $ 40,106 $ (11,721) Nonutility generation trusts investments 49,044 -- -- Nuclear decommissioning trust investments (86,221) (73,381) (30,704) Aquila notes receivable (91,335) -- -- Other comprehensive income 8,745 (49,653) -- Other investments (16,689) (116,285) (25,481) All other 52,482 (34,313) (52,289) --------- --------- --------- Total-Other $ (54,355) $(233,526) $(120,195) ========= ========= =========
(B) CONSOLIDATED STATEMENTS OF TAXES
2002 2001 2000 ---- ---- ---- RESTATED (IN THOUSANDS) Other Accumulated Deferred Income Taxes at December 31: Retirement Benefits $(381,285) $(133,282) $ (60,491) Oyster Creek securitization (Note 5H) 202,447 -- -- Purchase accounting basis differences (2,657) (147,450) -- Sale of generating assets (11,786) 207,787 -- Provision for rate refund (29,370) (46,942) -- All other (193,497) (203,809) 22,767 --------- --------- --------- Total-Other $(397,506) $(323,696) $ (37,724) ========= ========= =========
(C) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS FirstEnergy's regulated and competitive subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows:
2002 2001 2000 ------------------------------------------------------------------------------ (MILLIONS) Sales $453 $142 $315 Purchases 687 204 271 ------------------------------------------------------------------------------
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 FirstEnergy 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 FirstEnergy required additional power to meet its retail load requirements and, secondarily, to make sales to the wholesale market. 73 (D) STOCK BASED COMPENSATION Stock-based employee compensation expense recognized for the FE Programs' restricted stock during 2002, 2001 and 2000 totaled $2,259,000, $1,342,000 and $1,104,000, respectively. In addition, stock-based employee compensation expense of $206,000, $1,637,000 and $1,646,000 during 2002, 2001 and 2000, respectively, was recognized for EDCP stock units (see Note 5C - Stock Compensation Plans for further disclosure). (E) SFAS 115 ACTIVITY All other investments included under Investments other than cash and cash equivalents in the table in Note 2J - Supplemental Cash Flows Information include available-for-sale securities, at fair value, with the following results:
2002 2001 2000 ------ ------ ------ (IN THOUSANDS) Unrealized holding gains $ 202 $2,236 $ 992 Unrealized holding losses 4,991 432 70 Proceeds from sales 7,875 25 66 Gross realized gains 31 -- 46 Gross realized losses -- 3 -- ------ ------ ------
(F) DERIVATIVE INSTRUMENTS RECLASSIFICATIONS TO NET 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 (see Note 5I - Comprehensive Income for further disclosure). Other comprehensive income (loss) reclassified to net income in 2002 and 2001 totaled $(9.9) million and $30.7 million, respectively. These amounts were net of income taxes in 2002 and 2001 of $(6.8) million and $21.7 million, respectively. There were no reclassifications to net income in 2000. 10. OTHER RECENTLY ISSUED ACCOUNTING STANDARDS FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FirstEnergy does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period 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 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 $11.6 million. 74 11. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002 (C)(D) JUNE 30, 2002 (D) SEPTEMBER 30, 2002 (D) DECEMBER 31, 2002 ------------------------------------------------------------------------------------------------------------------------- AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED --------- --------- --------- --------- --------- --------- --------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues (a) $ 2,853.3 $ 2,853.3 $ 2,898.5 $ 2,898.5 $ 3,451.2 $ 3,451.2 $ 3,044.4 $ 3,027.5 Expenses (a) 2,363.6 2,362.3 2,230.4 2,272.7 2,681.7 2,724.0 2,746.8 2,741.1 Cumulative adjustment -- -- -- -- -- -- (93.7) -- --------- --------- --------- --------- --------- --------- --------- --------- Income Before Interest and Income Taxes 489.7 491 668.1 625.8 769.5 727.2 203.9 286.4 Net Interest Charges 278.7 278.7 250.3 250.3 220.4 220.4 216.2 212.0 Income Taxes 94.4 93.9 184.6 167.7 238.9 221.9 34.6 45.1 --------- --------- --------- --------- --------- --------- --------- --------- Income Before Discontinued Operations 116.6 118.4 233.2 207.8 310.3 284.8 (46.9) 29.3 Discontinued Operations -- -- -- -- -- -- -- (87.5) --------- --------- --------- --------- --------- --------- --------- --------- Net Income (Loss) $ 116.6 $ 118.4 $ 233.2 $ 207.8 $ 310.3 $ 284.8 $ (46.9) $ 58.2 ========= ========= ========= ========= ========= ========= ========= ========= Basic Earnings (Loss) Per Share of Common Stock $ .36 $ 0.41 $ .74 $ 0.71 $ .99 $ 0.97 $ (.16) $ (.20) Diluted Earnings (Loss) Per Share of Common Stock $ .36 $ 0.40 $ .73 $ 0.71 $ .98 $ 0.97 $ (.16) $ (.20) ========= ========= ========= ========= ========= ========= ========= =========
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, THREE MONTHS ENDED 2001 2001 2001 2001(B) ---------------------------------------------- --------- --------- --------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues $ 1,985.7 $ 1,804.1 $ 1,951.6 $ 2,257.9 Expenses 1,669.4 1,416.7 1,412.1 1,816.0 --------- --------- --------- --------- Income Before Interest and Income Taxes 316.3 387.4 539.5 441.9 Net Interest Charges 126.3 121.0 124.1 184.3 Income Taxes 83.8 120.4 181.3 89.0 --------- --------- --------- --------- Income Before Cumulative Effect of Accounting Change 106.2 146.0 234.1 168.6 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (8.5) -- -- -- --------- --------- --------- --------- Net Income $ 97.7 $ 146.0 $ 234.1 $ 168.6 ========= ========= ========= ========= Basic Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $ .49 $ .67 $ 1.07 $ .64 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (.04) -- -- -- --------- --------- --------- --------- Basic Earnings Per Share of Common Stock $ .45 $ .67 $ 1.07 $ .64 --------- --------- --------- --------- Diluted Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $ .49 $ .67 $ 1.06 $ .64 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (.04) -- -- -- --------- --------- --------- --------- Diluted Earnings Per Share of Common Stock $ .45 $ .67 $ 1.06 $ .64 ========= ========= ========= =========
(a) 2002 revenues and expenses related to trading activities reflect reclassifications as a result of implementing EITF Issue No. 02-03 (see Note 2C - Revenues). (b) Results for the former GPU companies are included from the November 7, 2001 acquisition date through December 31, 2001. (c) See Note 2L for discussion of revised financial data. (d) See Note 2(M) for discussion of Restated financial data. Related to impact of transition plan amortization and above works leases. (e) Includes the impact of above makes totaling $11.3 million, principally related to the recognition of a valuation allowance on a tax benefit previously recognized in the fourth quarter of 2002. On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000 (Merger Agreement). As a result of the merger, GPU's former wholly owned subsidiaries, including JCP&L, Met-Ed and Penelec, (collectively, the Former GPU Companies), became wholly owned subsidiaries of FirstEnergy. Under the terms of the Merger Agreement, GPU shareholders received the equivalent of $36.50 for each share of GPU common stock they owned, payable in cash and/or FirstEnergy common stock. GPU shareholders receiving FirstEnergy shares received 1.2318 shares of FirstEnergy common stock for each share of GPU common stock they exchanged. The cash portion of the merger consideration was approximately $2.2 billion and nearly 73.7 million shares of FirstEnergy common stock were issued to GPU shareholders for the share portion of the transaction consideration. The merger was accounted for by the purchase method of accounting and, accordingly, the Consolidated Statements of Income include the results of the Former GPU Companies beginning November 7, 2001. The assets acquired and liabilities assumed were recorded at estimated fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. The merger purchase accounting adjustments, which were recorded in the records of GPU's direct subsidiaries, primarily consist of: (1) revaluation of GPU's international operations to fair value; (2) revaluation of property, plant and equipment; (3) adjusting 75 preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (4) recognizing additional obligations related to retirement benefits; and (5) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The severance and compensation liabilities are based on anticipated workforce reductions reflecting duplicate positions primarily related to corporate support groups including finance, legal, communications, human resources and information technology. The workforce reductions represent the expected reduction of approximately 700 employees at a cost of approximately $140 million. Merger related staffing reductions began in late 2001 and the remaining reductions are anticipated to occur through 2003 as merger-related transition assignments are completed. The merger greatly expanded the size and scope of our electric business and the goodwill recognized primarily relates to the regulated services segment. The combination of FirstEnergy and GPU was a key strategic step in FirstEnergy achieving its vision of being the leading energy and related services provider in the region. The merger combined companies with the management, employee experience and technical expertise, retail customer base, energy and related services platform and financial resources to grow and succeed in a rapidly changing energy marketplace. The merger also allowed for a natural alliance of companies with adjoining service areas and interconnected transmission systems to eliminate duplicative costs, maximize efficiencies and increase management and operational flexibility in order to enhance operations and become a more effective competitor. Under the purchase method of accounting, tangible and identifiable intangible assets acquired and liabilities assumed are recorded at their estimated fair values. The excess of the purchase price, including estimated fees and expenses related to the merger, over the net assets acquired (which included existing goodwill of $1.9 billion), is classified as goodwill and amounts to an additional $2.3 billion. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed on the date of acquisition.
(IN MILLIONS) ----------- Current assets $ 1,027 Goodwill 3,698 Regulatory assets 4,352 Other 5,595 -------- Total assets acquired 14,672 -------- Current liabilities (2,615) Long-term debt (2,992) Other (4,785) -------- Total liabilities assumed (10,392) Net assets acquired pending sale 566 -------- Net assets acquired $ 4,846 --------
During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations; (2) updated valuations of GPU's international operations as of the date of the merger; (3) establishment of a reserve for deferred energy costs recognized prior to the merger; and (4) return to accrual adjustments for income taxes. As a result of these adjustments, goodwill increased by approximately $290 million, which is attributable to the regulated services segment. The following pro forma combined condensed statements of income of FirstEnergy give effect to the FirstEnergy/GPU merger as if it had been consummated on January 1, 2000, with the purchase accounting adjustments actually recognized in the business combination. The pro forma combined condensed financial statements have been prepared to reflect the merger under the purchase method of accounting with FirstEnergy acquiring GPU. In addition, the pro forma adjustments reflect a reduction in debt from application of the proceeds from certain pending divestitures as well as the related reduction in interest costs.
YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 ------- ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues $12,108 $11,703 Expenses 9,768 9,377 ------- ------- Income Before Interest and Income Taxes 2,340 2,326 Net Interest Charges 941 977 Income Taxes 561 527 ------- ------- Net Income $ 838 $ 822 ------- ------- Earnings per Share of Common Stock $ 2.87 $ 2.77 ------- -------
76 13. SUBSEQUENT EVENTS (UNAUDITED) 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 (see Note 7(D) Commitments, Guarantees and Contingencies - Environmental Matters). 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." 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. 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 (See Note 2(D)). 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 Judge ("ALJ") and directed Met-Ed and Penelec submit a position paper by May 2, 2003 on the status of the Settlement Stipulation in light of the Commonwealth Court's decision ("Court Order"). In summary, the Met-Ed and Penelec submitted to the PPUC the following position: - On January 16, 2003, the Pennsylvania Supreme Court denied or quashed all appeals arising from the Court Order, thus rendering the Court Order final. 77 - Because the parties sought to stay the PPUC's June 20, 2001 order in which the Settlement Stipulation was approved, all terms and conditions included therein that were not inconsistent with the Court Order remained in effect. - Only those provisions related to POLR cost recovery and POLR deferral, issues addressed by the PPUC and expressly rejected by the Commonwealth Court, must be removed from the Settlement Stipulation. - The GENCO Code of Conduct must be reinstated consistent with the Court Order. - All other provisions included in the Stipulation unrelated to these three issues remain in effect. On or about June 2, 2003, parties filed comments in response to the position presented by Met-Ed and Penelec. 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. Based upon these comments, it became clear that many of the parties not only disagreed with Met-Ed and Penelec, but also disagreed among themselves. Partially because of this lack of consensus among the parties, Met-Ed and Penelec submitted a letter on June 11, 2003, to the ALJ informing the ALJ and all other parties that Met-Ed and Penelec were voiding the Settlement Stipulation, pursuant to the termination provisions found therein. Notwithstanding the voiding of the Settlement Stipulation, Met-Ed and Penelec voluntarily agreed to retain virtually all of the customer benefits provided by the Settlement Stipulation, including, among others, funding for renewable energy resource and demand response programs. Met-Ed and Penelec also agreed to cap distribution rates at current levels through 2007, provided that the PPUC finds during the remanded merger saving proceedings that Met-Ed and Penelec have satisfied the public interest test applicable to mergers and leave the quantification of merger savings for a subsequent rate proceedings. 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. Met-Ed and Penelec believe that their actions in voiding the Settlement Stipulation will simplify the issues and limit them to the treatment of merger savings and whether Met-Ed's and Penelec's accounting is 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 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. Emdersa On April 18, 2003, FirstEnergy divested its ownership in 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. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million, or $0.23 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through current period earnings ($89.8 million, or $0.30 per share), partially offset by the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22.4 million, or $0.07 per share). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $67.4 million charge was an increase in common stockholders' equity of $22.4 million. The $67.4 million charge does not include the anticipated income tax benefits related to the abandonment, which were 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. 78 OTHER MATTERS- It is FirstEnergy's understanding that, as of August 18, 2003, five individual described herein shareholder-plaintiffs have filed separate complaints against FirstEnergy Corp. alleging various securities law violations in connection with the restatement of earnings period. 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. 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 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. It is clear 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., it is clear 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. 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. 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. 79 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. 80