10-Q/A 1 l03030ae10vqza.txt AMENDMENT NO. 1 TO FORM 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q/A AMENDMENT NO. 1 (MARK ONE) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO ----------------- ------------------- COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO. ----------- ------------------------------------------------------- ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (AN OHIO CORPORATION) 76 SOUTH MAIN STREET AKRON, OH 44308 TELEPHONE (800)736-3402
Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ---- ----- Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act): Yes X No ---- ----- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
OUTSTANDING CLASS AS OF AUGUST 8, 2003 ----- -------------------- FirstEnergy Corp., $.10 par value 297,636,276
This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, further investigation into the causes of the August 14, 2003, power outage and other similar factors. EXPLANATORY NOTE We are filing this Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (the "Report") to correct certain typographical and minor computational errors in Item 1 - FINANCIAL STATEMENTS - Note 6 to the Consolidated Financial Statements and Item 2 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION of the Report. This Amendment has no effect on previously reported results of operations or financial position. The complete amended and restated Item 1, which is included in its entirety below, reflects corrections to the tables included in Note 6 "Segment Information" as follows: For the three months ended June 30, 2003 - Income taxes for regulated services, competitive services and other, respectively, of $89 million, $(32) million and $(32) million, respectively, should have read $80 million, $(31) million and $(31) million, respectively. Income before discontinued operations and cumulative effect of accounting change for regulated services and competitive services, respectively, of $118 million and $(45) million, respectively, should have read $107 million and $(44) million, respectively. Net income (loss) for regulated services and competitive services, respectively, of $118 million and $(45) million, respectively, should have read $107 million and $(44) million, respectively. For the three months ended June 30, 2002 - External revenues for regulated services, competitive services and other, respectively, of $2,161 million, $696 million and $36 million, respectively, should have read $2,210 million, $590 million and $93 million, respectively. Internal revenues for regulated services and competitive services, respectively, of $177 million and $417 million, respectively, should have read $237 million and $357 million, respectively. Total revenues for regulated services, competitive services and other, respectively, of $2,338 million, $1,113 million and $161 million, respectively, should have read $2,447 million, $947 million and $218 million, respectively. For the six months ended June 30, 2003 - External revenues for regulated services and competitive services, respectively, of $4,398 million and $1,606 million, respectively, should have read $4,399 million and $1,605 million, respectively. Total revenues for regulated services and competitive services, respectively, of $4,896 million and $2,678 million, respectively, should have read $4,897 million and $2,677 million, respectively. Income taxes for regulated services, competitive services and other, respectively, of $248 million, $(63) million and $(62) million, respectively, should have read $234 million, $(61) million and $(61) million, respectively. Income before discontinued operations and cumulative effect of accounting change for regulated services, competitive services and other, respectively, of $345 million, $(89) million and $(105) million, respectively, should have read $323 million, $(100) million and $(104) million, respectively. Net income (loss) for regulated services, competitive services and other, respectively, of $446 million, $(88) million and $(165) million, respectively, should have read $424 million, $(99) million and $(164) million, respectively. For the six months ended June 30, 2002 - External revenues for regulated services and competitive services, respectively, of $4,156 million and $1,283 million, respectively, should have read $4,264 million and $1,175 million, respectively. Total revenues for regulated services and competitive services, respectively, of $4,688 million and $2,110 million, respectively, should have read $4,796 million and $2,002 million, respectively. The complete amended and restated Item 2, which is included in its entirety below, reflects the following corrections: Under the heading "RESULTS OF OPERATIONS": Under the subheading "Expenses": In the first sentence of the third paragraph, the decrease in other operating expenses of $9.6 million in the second quarter of 2003 should have read $7.1 million. In the last sentence of the sixth paragraph, the lower charges resulting from revised service life assumptions for generating plants of $14.1 million should have read $12.7 million. Under the heading "RESULTS OF OPERATIONS-BUSINESS SEGMENTS": In the third paragraph under the subheading "Regulated Services": In the third sentence, the increase in other operating expenses of $15.9 million and in depreciation and amortization expense of $10.6 million should have read $18.4 million and $8.1 million, respectively, In the sixth sentence, the increase in other operating expense of $29.9 million and in depreciation and amortization expense of $27.2 million should have read $32.4 million and $24.7 million, respectively. Under the heading "CAPITAL RESOURCES AND LIQUIDITY": Under the subheading "Cash Flows from Operating Activities": In the table, cash earnings for the three months ended June 30, 2003 of $509 million should have read $515 million, and for the three months ended June 30, 2002 of $530 million should have read $495 million. In the table, working capital and other for the three months ended June 30, 2003 of ($487) million should have read ($493) million, and for the three months ended June 30, 2002 of ($268) million should have read ($233) million. In the second paragraph, the change in funds used for working capital of $219 million should have read $260 million, and the decrease in cash earnings of $21 million should have read an increase in cash earnings of $20 million. Under the heading "IMPLEMENTATION OF ACCOUNTING STANDARD": The "Total as originally reported" for expenses in the chart entitled Impact of Recording Energy Trading Net for the three months and six months ended June 30, 2002 of $2,309 million and $4,701 million, respectively, should have read $2,323 million and $4,725 million, respectively. The "Total as currently reported" for expenses in the same chart as indicated above for the three months and six months ended June 30, 2002 of $2,259 million and $4,611 million, respectively, should have read $2,273 million and $4,635 million, respectively. TABLE OF CONTENTS
PAGES PART I. FINANCIAL INFORMATION Notes to Financial Statements............................................................. 1-20 FIRSTENERGY CORP. Consolidated Statements of Income......................................................... 21 Consolidated Balance Sheets............................................................... 22-23 Consolidated Statements of Cash Flows..................................................... 24 Report of Independent Auditors............................................................ 25 Management's Discussion and Analysis of Results of Operations and Financial Condition..................................................................... 26-49 PART II. OTHER INFORMATION
PART I. FINANCIAL INFORMATION FIRSTENERGY CORP. AND SUBSIDIARIES OHIO EDISON COMPANY AND SUBSIDIARIES THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES THE TOLEDO EDISON COMPANY AND SUBSIDIARY PENNSYLVANIA POWER COMPANY JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES METROPOLITAN EDISON COMPANY AND SUBSIDIARIES PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (UNAUDITED) 1 - FINANCIAL STATEMENTS: The principal business of FirstEnergy Corp. (FirstEnergy) is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), Pennsylvania Power Company (Penn), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). These utility subsidiaries are referred to throughout as "Companies." Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) with GPU, Inc., the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; FirstEnergy Nuclear Operating Company (FENOC); GPU Capital, Inc.; GPU Power, Inc.; and FirstEnergy Service Company (FESC). 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 holds FirstEnergy's interest in Great Lakes Energy Partners, LLC. GPU Capital owns and operates electric distribution systems in foreign countries (see Note 3) and GPU Power owns and operates generation facilities in foreign countries. FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies. Significant intercompany transactions have been eliminated. The Companies follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The condensed unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K, as amended where applicable, for the year ended December 31, 2002 for FirstEnergy and the Companies. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from those estimates. The reported results of operations are not indicative of results of operations for any future period. Certain prior year amounts have been reclassified to conform with the current year presentation, as discussed further in Note 5, as well as restated as discussed below. Preferred Securities The sole assets of the CEI subsidiary trust that is the obligor on the preferred securities included in FirstEnergy's and CEI's Capitalizations are $103.1 million aggregate principal amount of 9% junior subordinated debentures of CEI due December 31, 2006. CEI has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. Met-Ed and Penelec each formed statutory business trusts for the issuance of $100 million each of preferred securities due 2039 and included in FirstEnergy's, Met-Ed's and Penelec's respective capitalizations. Ownership of the respective Met-Ed and Penelec trusts is through separate wholly-owned limited partnerships, of which a wholly-owned subsidiary of each company is the sole general partner. In these transactions, the sole assets and sources of revenues of 1 each trust are the preferred securities of the applicable limited partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103.1 million each) of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. Securitized Transition Bonds In June 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on each of FirstEnergy's and JCP&L's Consolidated Balance Sheet. The transition bonds represent obligations only of the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer. Bondable transition property represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to the Issuer and 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. Pension and Other Postretirement Benefits As a result of GPU Service Inc. merging with FESC in the second quarter of 2003, operating company employees of GPU Service were transferred to JCP&L, Met-Ed and Penelec. Accordingly, FirstEnergy requested an actuarial study to update the pension and other post-employment benefit (OPEB) assets and liabilities for each of its subsidiaries. Based on the actuary's report, the accrued pension and OPEB costs for FirstEnergy and its subsidiaries as of June 30, 2003 increased (decreased) by the following amounts:
Pension OPEB ------- ---- (In thousands) OE......................... $ 50,937 $ 48,775 CEI........................ (16,699) (49,526) TE......................... (3,439) (24,476) Penn....................... 15,851 9,751 JCP&L...................... 78,549 86,333 Met-Ed..................... 47,219 59,405 Penelec.................... 70,693 87,314 Other subsidiaries......... (243,111) (217,576) ---------- ---------- Total FirstEnergy.......... $ -- $ -- =============== ===============
The corresponding adjustment related to these changes increased (decreased) other comprehensive income, deferred income taxes and receivables from/to associated companies in the respective operating company's financial statements. Derivative Accounting FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. 2 FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a portion of the anticipated interest 2nd QTR 10-Q 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 $110.8 million included in Accumulated Other Comprehensive Loss (AOCL) as of June 30, 2003, for derivative hedging activity, as compared to the March 31, 2003 balance of $105.8 million in net deferred losses, resulted from a $7.7 million reduction related to current hedging activity and a $12.7 million increase due to net hedge gains included in earnings during the three months ended June 30, 2003. Approximately $25.3 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 and 2003 to increase the variable-rate component of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations resulting in no ineffectiveness in these hedge positions. The swap agreements consummated in the second quarter of 2003 are based on a notional principal amount of $200 million. As of June 30, 2003, the notional amount of FirstEnergy's fixed-for-floating rate interest rate swaps totaled $550 million. 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 June 30, 2003, FirstEnergy's AOCL was approximately $534.1 million as compared to the December 31, 2002 balance of $656.1 million. A reconciliation of net income to comprehensive income for the three months and six months ended June 30, 2003 and 2002, is shown below:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, -------------------- ------------------ 2003 2002 2003 2002 ---- ---- ---- ---- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) (IN THOUSANDS) (IN THOUSANDS) Net income (loss).................... $(57,888) $207,898 $160,514 $326,166 Other comprehensive income, net of tax: Derivative hedge transactions...... (4,917) 535 (576) 36,379 Currency transactions (1).......... 89,790 -- 91,461 1 Available for sale securities...... 38,454 (2,140) 38,267 (1,411) --------- ----------- ---------- ------------ Comprehensive income................. $65,439 $206,293 $289,666 $361,135 ======= ======== ======== ========
(1) See Note 3 - International Operations (Emdersa Abandonment). 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. No material stock-based employee compensation expense is reflected in net income as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The effects of applying fair value accounting to FirstEnergy's stock options would be reductions to net income and earnings per share. The following table summarizes those effects. 3
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------- ---------------------- 2003 2002 2003 2002 ---- ---- ---- ---- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) (IN THOUSANDS) (IN THOUSANDS) Net income (loss), as reported........... $(57,588) $207,898 $160,514 $326,166 Add back compensation expense reported in net income, net of tax (based on APB 25)...................... 49 44 91 87 Deduct compensation expense based upon estimated fair value, net of tax.. (3,731) (2,556) (6,713) (3,956) -------------------------------------------------------------------------------------------------- Adjusted net income (loss)............... $(61,270) $205,386 $153,892 $322,297 ------------------------------------------------------------------------------------------------- Earnings (Loss) Per Share of Common Stock - Basic As Reported......................... $(0.20) $0.74 $0.55 $1.10 Adjusted............................ $(0.21) $0.73 $0.52 $1.09 Diluted As Reported......................... $(0.20) $0.73 $0.54 $1.09 Adjusted............................ $(0.21) $0.72 $0.52 $1.08
Changes in Previously Reported Income Statement Classifications FirstEnergy recorded an increase to income during the first quarter of 2002 of $31.7 million (net of income taxes of $13.6 million) relative to a decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified in operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the six months ended June 30, 2002 are reflected in the restatements shown below. As a result of FirstEnergy's divestiture of its ownership in GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) in April 2003 through the abandonment of its shares in the parent company of the Argentina operation (as further described in Note 3), FirstEnergy recorded a $67.4 million charge in the second quarter of 2003 on the Consolidated Statement of Income as "Discontinued Operations". This divestiture caused Emdersa's first quarter 2003 net income of approximately $6.9 million, which had been previously classified in its respective revenues and expense captions on the Consolidated Statement of Income, to be also reclassified as Discontinued Operations. Accordingly, Emdersa's Discontinued Operations reflect a $60.5 million net loss for the six months ended June 30, 2003 which included $6.9 million of after-tax earnings from the Argentina operation from the first quarter of 2003 - previously reported as $10.7 million of revenue, $0.1 million of expenses and $3.7 million of income taxes. The following table summarizes Emdersa's major assets and liabilities included in FirstEnergy's Consolidated Balance Sheet as of December 31, 2002: (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 ================================================ 4 RESTATEMENTS OF PREVIOUSLY REPORTED RESULTS FirstEnergy, OE, CEI and TE have restated their financial statements for the year ended December 31, 2002; for the three months ended March 31, 2003 and 2002; the six months ended June 30, 2003 and the three and six months ended June 30, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial adjustments recorded in the first quarter of 2003 that related to 2002 are now reported in results for the earlier periods. The net impact of these adjustments decreased net income by $6.2 million in the first quarter of 2003. Included in the adjustments are the impact in the first and second quarters of 2003 of recognizing revenue on the deferred costs incurred subsequent to the merger associated with this Company's rate matter in Pennsylvania (see Note 4). The impact of this restatement increased net income in the first quarter, 2002 by $12 million and decreased net income in the second quarter 2002 by $8 million. See note 2(M) of the FirstEnergy, OE, CEI and TE Form 10-K/A for further discussion of the restatements. Since the results for the quarter ended March 31, 2003 have been restated as discussed above and the results of operations for the six months ended June 30, 2003 reflect these restated results, the June 30, 2003 amounts are restated. Transition Cost Amortization As discussed in Regulatory Matters in Note 4, FirstEnergy, OE, CEI and TE amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition plan through the end of 2009. The following table summarizes the previously reported transition cost amortization and the restated amounts under the revised method for the three months and six months ended June 30, 2002:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ------------------------- ---------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) OE .................. $ 75,026 $ 82,326 $151,202 $150,502 CEI ................. 11,655 36,455 24,796 73,596 TE .................. 6,325 23,925 14,217 48,217 -------- -------- -------- -------- Total FirstEnergy $ 93,006 $142,706 $190,215 $272,315 ======== ======== ======== ========
Above-Market Lease Costs In 1997, FirstEnergy was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant were recorded as regulatory assets because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $722 million (CEI - $611 million; TE - $111 million) associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS No. 142. The total above market lease obligation of $755 million (CEI - $457 million, TE - $298 million) associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization 5 schedules for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI and 2007 for TE. The effects of these changes on the Consolidated Statement of Income previously reported for the three months ended March 31, 2003, were disclosed in Amendment No. 1 on Form 10-Q/A for the quarter ended March 31, 2003. The effects of these changes on the Consolidated Statements of Income previously reported for the three months and six months ended June 30, 2002 are as follows: FIRSTENERGY
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues $2,898,573 $2,898,573 $5,751,851 $5,751,851 Expenses 2,230,409 2,272,659 4,594,043 4,635,001 ----------- ----------- ----------- ----------- Income before interest and income taxes 668,164 625,914 1,157,808 1,116,850 Net interest charges 250,282 250,282 529,004 529,004 Income taxes 184,572 167,734 279,001 261,680 ------------ ------------ ------------ ------------ Net income $ 233,310 $ 207,898 $ 349,803 $ 326,166 =========== =========== =========== =========== Basic earnings per share of common stock $.80 $.71 $1.19 $1.11 Diluted earnings per share of common stock $.79 $.71 $1.19 $1.11
OE
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) Operating revenues $744,550 $744,550 $1,452,349 $1,452,349 Operating expenses and taxes 605,946 611,069 1,216,681 1,211,518 --------- --------- ----------- ----------- Operating income 138,604 133,481 235,668 240,831 Other income 15,087 15,087 15,599 15,599 Net interest charges 35,856 35,856 77,081 77,081 ---------- ---------- ------------- ------------- Net income 117,835 112,712 174,186 179,349 Preferred stock dividend requirements 2,597 2,597 5,193 5,193 ----------- ----------- -------------- -------------- Earnings on common stock $115,238 $110,115 $ 168,993 $ 174,156 ======== ======== =========== ===========
CEI
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) Operating revenues $462,874 $462,874 $887,851 $896,151 Operating expenses and taxes 350,120 355,799 719,775 731,551 --------- --------- --------- --------- Operating income 112,754 107,075 168,076 164,600 Other income 3,356 3,356 8,597 8,597 Net interest charges 46,750 46,750 94,617 94,617 ---------- ---------- ----------- ---------- Net income 69,360 63,681 82,056 78,580 Preferred stock dividend requirements 3,054 3,054 11,310 9,610 ----------- ----------- ----------- --------- Earnings on common stock $ 66,306 $ 60,627 $ 70,746 $ 68,970 ========= ========= ========== =========
TE
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) Operating revenues $250,307 $250,307 $494,474 $502,874 Operating expenses and taxes 216,148 222,658 450,657 464,537 --------- --------- --------- --------- Operating income 34,159 27,649 43,817 38,337 Other income 3,743 3,743 8,086 8,086 Net interest charges 14,859 14,859 29,568 29,568 ---------- ---------- ---------- ---------- Net income 23,043 16,533 22,335 16,855 Preferred stock dividend requirements 2,210 2,210 6,934 6,934 ----------- ----------- ----------- ----------- Earnings on common stock $ 20,833 $ 14,323 $ 15,401 $ 9,921 ========= ========= ========= ==========
6 The effects of these changes on net cash provided from operating activities on the Consolidated Statement of Cash Flows previously reported for the three months ended March 31, 2003, were disclosed in Amendment No. 1 on Form 10-Q/A for the quarter ended March 31, 2003. The effects of these changes on the Consolidated Statements of Cash Flows previously reported for the three months and six months ended June 30, 2002 are as follows: FE
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $233,310 $207,898 $349,803 $326,166 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 250,705 300,405 513,533 609,779 Nuclear fuel and lease amortization 19,598 19,598 40,563 40,563 Other amortization (4,386) (4,386) (7,923) (7,923) Deferred costs recoverable as regulatory assets (68,936) (55,136) (139,070) (146,070) Deferred income taxes 50,355 33,517 43,421 12,500 Investment tax credits (6,967) (6,967) (13,713) (13,713) Cumulative effect of accounting change (Note 5) -- -- (45,300) -- Receivables (150,157) (150,157) (83,567) (90,062) Materials and supplies (21,742) (21,742) (3,579) (3,579) Accounts payable 47,766 47,766 37,774 44,762 Accrued taxes 4,422 4,422 86,719 86,719 Accrued interest (106,136) (106,136) (19,557) (19,557) Deferred rents & sale/leaseback (121,642) (142,892) (50,204) (98,492) Prepayments & other (128,937) (128,937) (19,386) (19,386) Other 264,870 264,870 36,693 4,500 ---------- ---------- ---------- ----------- Net cash provided from operating schedules $ 262,123 $ 262,123 $726,207 $726,207 --------- --------- -------- --------
OE
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $117,835 $112,712 $174,186 $179,349 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 91,521 98,821 183,651 174,551 Nuclear fuel and lease amortization 12,133 12,133 23,535 23,535 Deferred income taxes (8,886) (11,386) (22,056) (18,766) Investment tax credits (3,762) (3,439) (7,535) (6,888) Receivables (31,345) (31,345) 32,803 32,803 Materials and supplies (3,158) (3,158) (4,800) (4,800) Accounts payable (1,166) (1,166) (19,461) (19,461) Accrued taxes 149,376 149,376 206,260 206,260 Accrued interest (8,200) (8,200) (1,963) (1,963) Deferred rents & sale/leaseback (31,865) (31,865) (182) (182) Prepayments & other 15,178 15,178 31,273 31,273 Other (4,232) (4,232) (34,771) (34,771) ---------- ---------- ---------- ---------- Net cash provided from operating schedules $293,429 $293,429 $560,940 $560,940 -------- -------- -------- --------
7 CEI
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income $69,360 $63,681 $82,056 $78,580 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 28,333 53,133 56,804 105,604 Nuclear fuel and lease amortization 4,794 4,794 10,784 10,784 Other amortization (4,275) (4,275) (8,167) (8,167) Deferred income taxes 5,904 2,024 13,100 2,906 Investment tax credits (1,129) (1,270) (2,031) (2,313) Receivables (38,473) (38,473) (31,657) (31,557) Materials and supplies (1,840) (1,840) (3,206) (3,206) Accounts payable 8,057 8,057 26,379 26,379 Other (27,779) (42,879) (13,588) (48,536) --------- --------- ---------- ---------- Net cash provided from operating schedules $ 42,952 $ 42,952 $130,474 $130,474 -------- -------- -------- --------
TE
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ----------------------------- ------------------------------ AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 23,043 $ 16,533 $ 22,335 $ 10,209 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 19,748 37,348 41,116 75,116 Nuclear fuel and lease amortization 2,671 2,671 6,244 6,244 Deferred income taxes 578 (4,322) 5,892 (2,963) Investment tax credits (487) (527) (973) (1,053) Receivables (18,762) (18,762) 1,260 1,260 Materials and supplies (1,169) (1,169) (1,820) (1,820) Accounts payable (9,210) (9,210) (6,349) (7,049) Other (40,885) (47,035) (26,413) (38,652) --------- --------- --------- ---------- Net cash provided from operating activities $(24,473) $(24,473) $ 41,292 $ 41,292 --------- -------- -------- ---------
2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $3.1 billion (OE-$268 million, CEI-$312 million, TE-$169 million, Penn-$123 million, JCP&L-$462 million, Met-Ed-$288 million, Penelec-$328 million, ATSI-$131 million, FES-$823 million and other subsidiaries-$147 million) for property additions and improvements from 2003-2007, of which approximately $733 million (OE-$85 million, CEI-$99 million, TE-$56 million, Penn-$53 million, JCP&L-$112 million, Met-Ed-$51 million, Penelec-$49 million, ATSI-$25 million, FES-$124 million and other subsidiaries-$79 million) is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $481 million (OE-$59 million, CEI-$51 million, TE-$31 million, Penn-$39 million and FES-$301 million), of which approximately $76 million (OE-$28 million, CEI-$17 million, TE-$12 million and Penn-$19 million) applies to 2003. Guarantees and Other Assurances As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of June 30, 2003, outstanding guarantees and other assurances aggregated $1.050 billion. 8 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 $918.2 million as of June 30, 2003 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $24.5 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 June 30, 2003, rating-contingent collateralization totaled $106.8 million. FirstEnergy monitors these collateralization provisions and updates its total exposure monthly. Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required 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. 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. On August 7, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant 9 between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures they may be required, may have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. 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 June 30, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable societal benefits charge. The Companies have total accrued liabilities aggregating approximately $53.8 million (JCP&L-$47.1 million, CEI-$2.5 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.3 million and other-$3.5 million) as of June 30, 2003. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations but is unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. Other Commitments and Contingencies GPU made significant investments in foreign businesses and facilities through its GPU Capital and GPU Power subsidiaries. Although FirstEnergy attempts to mitigate its risks related to foreign investments, it faces additional risks inherent in operating in such locations, including foreign currency fluctuations. EI Barranquilla, a wholly owned subsidiary of GPU Power, is a 28.67% equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which owns a Colombian independent power generation project. GPU Power is committed through September 30, 2003, under certain circumstances, to make additional standby equity contributions to TEBSA of $21.3 million, which FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA project is $226 million as of June 30, 2003. The lenders include the Overseas Private Investment Corporation, US Export Import Bank and a commercial bank syndicate. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6.0 million (subject to escalation) under the project's operations and maintenance agreement. FirstEnergy provided the TEBSA project lenders a $50 million letter of credit (LOC) (under FirstEnergy's existing $250 million LOC capacity available as part of a $1.5 billion FirstEnergy credit facility) to obtain TEBSA lender consent as substitute collateral for the release of the assets for FirstEnergy to abandon its Argentina operations, Emdersa (see Note 3 below). 10 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. Legal Matters It is FirstEnergy's understanding that, as of August 18, 2003, five individual shareholder-plaintiffs have filed separate complaints against FirstEnergy alleging various securities law violations in connection with the restatement of earnings described herein. Most of these complaints have not yet been officially served on the Company. Moreover, FirstEnergy is still reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is, however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against it, the most significant of which are described herein. 3 - DIVESTITURES: INTERNATIONAL OPERATIONS- FirstEnergy had identified certain former GPU international operations for divestiture within one year of the merger. These operations constitute individual "lines of business" as defined in APB Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's 2001 Consolidated Statement of Income. Additionally, assets and liabilities of these international operations had been segregated under separate captions on the Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current 11 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 ($32.5 million net of tax) 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, which is contingent upon bondholder approval, 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. GPU's former Argentina operations were also identified by FirstEnergy for divestiture within one year of the merger. FirstEnergy determined the fair value of Emdersa, based on the best available information as of the date of the merger. Subsequent to that date, a number of economic events occurred in Argentina which affected FirstEnergy's ability to realize Emdersa's estimated fair value. These events included currency devaluation, restrictions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. FirstEnergy did not reach a definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these assets were no longer classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2002. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). In October 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy also recognized a currency translation adjustment (CTA) in other comprehensive income (OCI) of $91.5 million as of December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This adjustment represented the impact of translating Emdersa's financial statements from its functional currency to the U.S. dollar for GAAP financial reporting. On April 18, 2003, FirstEnergy divested its ownership in Emdersa 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 $89.8 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. SALE OF GENERATING ASSETS- In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy for damages, based on the anticipatory breach of the agreement. On February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's request for arbitration against NRG. The arbitration hearing is scheduled for the week of February 23, 2004. 12 In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approximately $74 million ($43 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 4 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the Companies' respective state regulatory plans: - allowing the Companies' electric customers to select their generation suppliers; - establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; - allowing recovery of potentially stranded investment (sometimes referred to as transition costs); - itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the Companies' electric generation businesses; and - continuing regulation of the Companies' transmission and distribution systems. Ohio In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Ohio Companies were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the respective transition cost recovery period. If the customer shopping goals established in the agreement had not been achieved by the end of 2005, the transition cost recovery periods could have been 13 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 had been 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 2002, JCP&L received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs and which provided for a usage-based non-bypassable transition bond charge (TBC) and for the transfer of the bondable transition property to another entity. JCP&L sold the transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet. JCP&L's PLR obligation to provide basic generation service (BGS) to non-shopping customers is supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of June 30, 2003, the accumulated deferred cost balance totaled approximately $450 million, after the charge discussed below. The NJBPU also allowed securitization of JCP&L's deferred balance to the extent permitted by law upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization. Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the NJBPU in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which would reduce 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 $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. 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. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. On July 25, 2003, the NJBPU approved a Stipulation Settlement between the parties and authorized the recovery of the total $135 million of buyout costs. 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 14 beginning August 1, 2003. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances. Pennsylvania The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's 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. In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision also affirmed the PPUC decision regarding the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. In September 2002, FirstEnergy established reserves for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court decision which effectively affirmed the PPUC's order approving the merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. Because FirstEnergy had already reserved for the deferred energy costs and FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and Penelec believe that the disallowance of continued CTC recovery of PLR costs will not have a future adverse financial impact during that period. 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. 15 Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale currently runs through December 2003 and will be automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at or below the shopping credit for their uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and amounts recovered through their capped generation rates. 5 - NEW ACCOUNTING STANDARDS: In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations." That 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 (ARO) be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003 asset retirement costs were recorded in the amount of $602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.109 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.243 billion. FirstEnergy expects substantially all nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn would be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for these operating companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $174.7 million increase to income, $102.1 million net of tax, or $0.35 per share of common stock (basic and diluted). FirstEnergy recorded an ARO for nuclear decommissioning ($1.096 billion) of the Beaver Valley 1, Beaver Valley 2, Davis-Besse, Perry, and TMI-2 nuclear generation facilities with the remaining ARO related to Bruce Mansfield's sludge impoundment facilities and two coal ash disposal sites. The Company maintains nuclear decommissioning trust funds, which had balances as of June 30, 2003 of $1.161 billion. This amount represents the fair value of the assets that are legally restricted for purposes of settling the nuclear decommissioning ARO. The following table provides the beginning and ending aggregate carrying amount of the total ARO and the changes to the balance during the second quarter and the first six months of 2003.
PERIODS ENDED JUNE 30, 2003 ----------------------------------- ARO RECONCILIATION THREE MONTHS SIX MONTHS -------------------------------------------------------------------------------------- (IN MILLIONS) Balance at beginning of period .................. $1,127 $1,109 Liabilities incurred in the current period....... -- -- Liabilities settled in the current period........ -- -- Accretion expense................................ 18 36 Revisions in estimated cash flows................ -- -- -------------------------------------------------------------------------------------- ENDING BALANCE AS OF JUNE 30, 2003............... $1,145 $1,145 --------------------------------------------------------------------------------------
The following table provides on an adjusted basis the year-end balance of the ARO related to nuclear decommissioning and sludge impoundment for 2002, as if SFAS 143 had been adopted on January 1, 2002. 16
ADJUSTED ARO RECONCILIATION --------------------------------------------------------------------------- (IN MILLIONS) Beginning balance as of January 1, 2002......................... $1,042 Accretion 2002.................................................. 67 --------------------------------------------------------------------------- ENDING BALANCE AS OF DECEMBER 31, 2002.......................... $1,109 ---------------------------------------------------------------------------
In accordance with SFAS 143 FirstEnergy ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates that are applied to the generation assets. This practice recognizes accumulated depreciation in excess of the historical cost of an asset, because the removal cost exceeds the estimated salvage value. The change in accounting resulted in a $60 million credit to income as part of the SFAS 143 cumulative effect adjustment. Beginning in 2003 depreciation rates applied to non-regulated generation assets exclude the cost of removal component and cost of removal is charged to expense rather than charged to the accumulated provision for depreciation. In accordance with SFAS 71, the regulated plant assets will continue the accounting practice of depreciating assets using a cost of removal component in the depreciation rates. The net removal cost credit balance included in the accumulated provision for regulated assets as of June 30, 2003 was approximately $312.5 million. The following table provides, on an adjusted basis, the effect on income as if the accounting for SFAS 143 had been applied during the second quarter and first six months of 2002.
PERIOD ENDED JUNE 30, 2002 EFFECT OF THE CHANGE IN ACCOUNTING -------------------------- PRINCIPLE APPLIED RETROACTIVELY TO 2002 THREE SIX INCREASE(DECREASE) MONTHS MONTHS ------ ------ (RESTATED - SEE NOTE 1) (IN MILLIONS) Reported net income........................... $208 $326 ------------------------------------------------------------------------------ Elimination of decommissioning expense........ 26 52 Depreciation of asset retirement cost......... (1) (2) Accretion of ARO liability.................... (9) (18) Income tax effect............................. (7) (13) ----------------------------------------------------------------------------- Net earnings effect........................... 9 19 ----------------------------------------------------------------------------- Net income adjusted........................... $217 $345 ============================================================================ Basic earnings per share of common stock: Net income as previously reported............. $0.71 $1.11 Adjustment for effect of change in accounting principle applied retroactively.. .03 0.06 ----------------------------------------------------------------------------- Net income adjusted........................... $0.74 $1.17 ============================================================================ Diluted earnings per share of common stock: Net income as previously reported............. $0.70 $1.10 Adjustment for effect of change in accounting principle applied retroactively.. 0.03 0.06 ---------------------------------------------------------------------------- Net income adjusted........................... $0.73 $1.16 ============================================================================
In January 2003, the FASB issued an interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (FirstEnergy's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. 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- 17 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, increasing assets and liabilities by $11.6 million. Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods beginning before June 15, 2003, which continue to be applied based on their original effective dates. FirstEnergy is currently assessing the new standard and has not yet determined the impact on its financial statements. In 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 immediately 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. 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. 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. In June 2002, the EITF reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. Prior to its adoption for 2002 year end reporting, FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation. In addition, the related KWH sales and purchases statistics described under Management's Discussion and Analysis of Results of Operations and Financial Condition were reclassified. The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations. 18
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ---------------------- ---------------------- 2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES REVENUES EXPENSES ------------------------------------------------------------------------------------------------ RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) (IN MILLIONS) (IN MILLIONS) Total as originally reported............ $2,949 $2,323 $5,842 $4,725 Adjustment.............................. (50) (50) (90) (90) ------------------------------------------------------------------------------------------------ Total as currently reported............. $2,899 $2,273 $5,752 $4,635 ===============================================================================================
6 - SEGMENT INFORMATION: FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of interest expense related to the 2001 merger acquisition debt; corporate support services and the international businesses acquired in the 2001 merger. FirstEnergy's primary segment is its regulated services segment, which includes eight electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segment consists of the subsidiaries that operate unregulated energy and energy-related businesses. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier. The regulated services segment obtains a portion of its required generation through power supply agreements with the competitive services segment. 19 SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING SERVICES SERVICES OTHER ADJUSTMENTS CONSOLIDATED --------- ----------- ----- ------------ ------------ (IN MILLIONS) THREE MONTHS ENDED: JUNE 30, 2003 External revenues..................... $ 2,083 $ 740 $ 22 $ 18(a) $ 2,863 Internal revenues..................... 233 512 147 (892)(b) -- Total revenues..................... 2,316 1,252 169 (874) 2,863 Depreciation and amortization......... 291 8 10 -- 309 Net interest charges.................. 132 11 104 (41)(b) 206 Income taxes.......................... 80 (31) (31) -- 18 Income before discontinued operations and cumulative effect of accounting change 107 (44) (54) -- 9 Net income (loss)..................... 107 (44) (121) -- (58) Total assets.......................... 30,123 2,499 1,403 -- 34,025 Property additions.................... 92 79 29 -- 200 JUNE 30, 2002 (RESTATED - SEE NOTE 1) External revenues..................... $ 2,210 $ 590 $ 93 $ 6(a) $ 2,899 Internal revenues..................... 237 357 125 (719)(b) -- Total revenues..................... 2,447 947 218 (713) 2,899 Depreciation and amortization......... 282 6 12 -- 300 Net interest charges.................. 156 7 102 (15)(b) 250 Income taxes.......................... 196 5 (33) -- 168 Net income (loss)..................... 248 7 (47) -- 208 Total assets.......................... 30,261 2,010 2,009 -- 34,280 Property additions.................... 120 72 32 -- 224 SIX MONTHS ENDED: JUNE 30, 2003 External revenues..................... $ 4,399 $1,605 $ 62 $ 31(a) $ 6,097 Internal revenues..................... 498 1,072 271 (1,841)(b) -- Total revenues..................... 4,897 2,677 333 (1,810) 6,097 Depreciation and amortization......... 597 16 21 -- 634 Net interest charges.................. 257 21 209 (75)(b) 412 Income taxes.......................... 234 (61) (61) -- 112 Income before discontinued operations and cumulative effect of accounting change 323 (100) (104) -- 119 Net income (loss)..................... 424 (99) (164) -- 161 Total assets.......................... 30,123 2,499 1,403 -- 34,025 Property additions.................... 210 158 56 -- 424 JUNE 30, 2002 (RESTATED - SEE NOTE 1) External revenues..................... $ 4,264 $1,175 $ 301 $ 12(a) $ 5,752 Internal revenues..................... 532 827 242 (1,601)(b) -- Total revenues..................... 4,796 2,002 543 (1,589) 5,752 Depreciation and amortization......... 573 13 24 -- 610 Net interest charges.................. 317 17 224 (29)(b) 529 Income taxes.......................... 358 (37) (59) -- 262 Net income (loss)..................... 447 (53) (68) -- 326 Total assets.......................... 30,261 2,010 2,009 -- 34,280 Property additions.................... 264 110 46 -- 420
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. 20 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ ------------------------ 2003 2002 2003 2002 ---------- ---------- ---------- ---------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES: Electric utilities..................................... $2,082,659 $2,210,316 $4,399,023 $4,264,292 Unregulated businesses................................. 780,487 688,257 1,697,879 1,487,559 ------------ ------------ ----------- ----------- Total revenues..................................... 2,863,146 2,898,573 6,096,902 5,751,851 ----------- ----------- ----------- ----------- EXPENSES: Fuel and purchased power............................... 1,121,553 766,288 2,314,363 1,430,328 Purchased gas.......................................... 128,634 145,954 358,099 352,181 Other operating expenses............................... 907,854 914,906 1,806,900 1,925,619 Provision for depreciation and amortization............ 309,022 300,405 633,884 609,779 General taxes.......................................... 163,042 145,106 341,324 317,094 ------------ ------------ ------------ ------------ Total expenses..................................... 2,630,105 2,272,659 5,454,570 4,635,001 ----------- ----------- ----------- ----------- INCOME BEFORE INTEREST AND INCOME TAXES................... 233,041 625,914 642,332 1,116,850 ------------ ------------ ------------ ----------- NET INTEREST CHARGES: Interest expense....................................... 199,670 231,782 400,320 492,247 Capitalized interest................................... (7,622) (6,605) (16,774) (12,419) Subsidiaries' preferred stock dividends................ 13,860 25,105 28,402 49,176 ------------- ------------- -------------------------- Net interest charges............................... 205,908 250,282 411,948 529,004 ------------ ------------ ------------ ------------ INCOME TAXES.............................................. 17,649 167,734 111,422 261,680 ------------- ------------ ------------ ------------ INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE................. 9,484 207,898 118,962 326,166 Discontinued operations (net of income taxes of $3,700,000 in the six months period) (Note 3)..................... (67,372) -- (60,495) -- Cumulative effect of accounting change (net of income taxes of $72,516,000) (Note 5)............................... -- -- 102,147 -- ------------------------------------------------------------ NET INCOME (LOSS)......................................... $ (57,888) $ 207,898 $ 160,614 $ 326,166 ============= =========== =========== =========== BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change.......................... $ .03 $ .71 $ .41 $1.11 Discontinued operations (net of income taxes) (Note 3). (.23) -- (.21) -- Cumulative effect of accounting change (net of income taxes) (Note 5)............................................. -- -- .35 -- ------- ------ ------ ----- Net income (loss)...................................... $ (.20) $ .71 $ .55 $1.11 ====== ====== ====== ===== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING............................................ 294,166 293,080 294,026 292,935 ======= ======= ======= ======= DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change.......................... $ .03 $ .71 $ .40 $1.11 Discontinued operations (net of income taxes) (Note 3). (.23) -- (.21) -- Cumulative effect of accounting change (net of income taxes) (Note 5).............................................. -- -- .35 -- ------ ------ ------ ----- Net income (loss)...................................... $ (.20) $ .71 $ .54 $1.11 ====== ====== ====== ===== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING............................................ 295,888 294,589 295,355 294,472 ======= ======= ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $ .75 $ .75 ===== ===== ====== ======
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 21 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
(UNAUDITED) JUNE 30, DECEMBER 31, 2003 2002 ---------- ------------- RESTATED (SEE NOTE 1) (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................................. $ 64,204 $ 196,301 Receivables- Customers (less accumulated provisions of $51,644,000 and $52,514,000 respectively, for uncollectible accounts)............................. 1,133,619 1,153,486 Other (less accumulated provisions of $8,003,000 and $12,851,000, respectively, for uncollectible accounts)............................. 507,635 469,606 Materials and supplies, at average cost- Owned................................................................... 292,728 253,047 Under consignment....................................................... 167,889 174,028 Other..................................................................... 327,847 203,630 ------------- ------------- 2,493,922 2,450,098 PROPERTY, PLANT AND EQUIPMENT: In service................................................................ 21,460,203 20,372,224 Less--Accumulated provision for depreciation.............................. 9,152,201 8,552,927 ------------- ------------- 12,308,002 11,819,297 Construction work in progress............................................. 606,234 859,016 -------------- -------------- 12,914,236 12,678,313 INVESTMENTS: Capital trust investments................................................. 1,028,433 1,079,435 Nuclear plant decommissioning trusts...................................... 1,161,259 1,049,560 Letter of credit collateralization........................................ 277,763 277,763 Other..................................................................... 917,251 918,874 ------------- ------------- 3,384,706 3,325,632 DEFERRED CHARGES: Regulatory assets......................................................... 8,088,548 8,753,401 Goodwill.................................................................. 6,249,363 6,278,072 Other..................................................................... 893,765 900,837 -------------- -------------- 15,231,676 15,932,310 -------------- -------------- $34,024,540 $34,386,353 ============== ==============
22 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
(UNAUDITED) JUNE 30, DECEMBER 31, 2003 2002 ----------- ------------- RESTATED (SEE NOTE 1) (IN THOUSANDS) CAPITALIZATION AND LIABILITIES CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... $ 1,328,415 $ 1,702,822 Short-term borrowings..................................................... 1,045,067 1,092,817 Accounts payable.......................................................... 857,724 906,468 Accrued taxes............................................................. 474,754 455,121 Other..................................................................... 982,520 1,093,815 ----------- ----------- 4,688,480 5,251,043 CAPITALIZATION: Common stockholders' equity- Common stock, $.10 par value, authorized 375,000,000 shares - 297,636,276 shares outstanding........................................ 29,764 29,764 Other paid-in capital................................................... 6,121,164 6,120,341 Accumulated other comprehensive loss.................................... (534,084) (656,148) Retained earnings....................................................... 1,575,153 1,634,981 Unallocated employee stock ownership plan common stock - 3,378,651 and 3,966,269 shares, respectively (67,246) (78,277) ----------- ----------- Total common stockholders' equity................................... 7,124,751 7,050,661 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption..................................... 335,123 335,123 Subject to mandatory redemption......................................... 18,517 18,521 Subsidiary-obligated mandatorily redeemable preferred securities.......... 284,834 409,867 Long-term debt............................................................ 11,239,278 10,872,216 ----------- ----------- 19,002,503 18,686,388 DEFERRED CREDITS: Accumulated deferred income taxes......................................... 2,066,541 2,069,682 Accumulated deferred investment tax credits............................... 224,759 236,184 Asset retirement obligations.............................................. 1,144,564 -- Nuclear plant decommissioning costs....................................... -- 1,243,558 Power purchase contract loss liability.................................... 3,022,798 3,136,538 Retirement benefits....................................................... 1,723,069 1,564,930 Lease market valuation liability.......................................... 1,063,600 1,106,000 Other..................................................................... 1,088,226 1,092,030 ----------- ----------- 10,333,557 10,448,922 COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)........................... ----------- ----------- $34,024,540 $34,386,353 =========== ===========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets. 23 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------- ----------------------- 2003 2002 2003 2002 --------- --------- --------- ----------- RESTATED RESTATED (SEE NOTE 1) (SEE NOTE 1) (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)......................................... $ (57,888) $ 207,898 $ 160,614 $ 326,166 Adjustments to reconcile net income (loss) to net cash from operating activities- Provision for depreciation and amortization........ 309,022 300,405 633,884 609,779 Nuclear fuel and lease amortization................ 15,578 19,598 30,496 40,563 Other amortization, net............................ (409) (4,386) (5,022) (7,923) Deferred costs recoverable as regulatory assets.... 81,558 (55,136) 42,810 (146,070) Deferred income taxes, net......................... (52,906) 33,517 (21,554) 12,500 Investment tax credits, net........................ (6,247) (6,967) (12,506) (13,713) Disallowed regulatory assets (Note 4).............. 158,500 -- 152,500 -- Discontinued operations (Note 3)................... 67,372 -- 60,495 -- Cumulative effect of accounting change (Note 5).... -- -- (174,663) -- Receivables........................................ (58,659) (150,157) (60,557) (90,062) Materials and supplies............................. (45,397) (21,742) (33,984) (3,579) Accounts payable................................... (27,928) 47,766 (35,043) 44,762 Accrued taxes...................................... (75,699) 4,422 21,854 86,719 Accrued interest................................... (105,277) (106,136) (15,678) (19,557) Deferred lease costs............................... (62,370) (142,892) (79,962) (98,492) Prepayments........................................ (50,885) (128,937) (120,558) (19,386) Other.............................................. (66,634) 264,870 (59,133) 4,500 ----------- ----------- ----------- ----------- Net cash provided from operating activities...... 21,731 262,123 483,993 726,207 ----------- ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... 722,041 261,699 1,019,737 366,730 Short-term borrowings, net........................... 189,741 -- -- 30,551 Redemptions and Repayments- Preferred stock...................................... (125,337) (5,000) (125,337) (190,299) Long-term debt....................................... (815,166) (194,738) (1,016,032) (378,643) Short-term borrowings, net........................... -- (85,005) (47,749) -- Common stock dividend payments......................... (110,284) (109,876) (220,443) (219,602) ---------- ----------- ----------- ---------- Net cash used for financing activities........... (139,005) (132,920) (389,824) (391,263) ---------- ----------- ----------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (199,742) (224,399) (424,161) (419,691) Proceeds from sale of assets........................... 5,877 155,034 66,449 155,034 Proceeds from note receivable.......................... 19,000 -- 19,000 -- Avon cash and cash equivalents (Note 3)................ -- (380,496) -- 31,326 Proceeds from nonutility generation trusts............. -- -- 106,327 -- Cash investments....................................... (9,650) 68,365 15,065 64,022 Other.................................................. 75,957 (36,374) (8,946) (26,763) ----------- ----------- ------------ ----------- Net cash used for investing activities........... (108,558) (417,870) (226,266) (196,072) ---------- ---------- ---------- ---------- Net increase (decrease) in cash and cash equivalents...... (225,832) (288,667) (132,097) 138,872 Cash and cash equivalents at beginning of period.......... 290,036 647,717 196,301 220,178 ---------- ---------- ---------- ---------- Cash and cash equivalents at end of period................ $ 64,204 $ 359,050 $ 64,204 $ 359,050 ========== ========= ========== =========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 24 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of FirstEnergy Corp.: We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of June 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the quarter ended June 30, 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for goodwill in 2002 as discussed in Note 2(E) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements for the year ended December 31, 2002 as discussed in Note 2(L) and Note 2(M) to those consolidated financial statements) dated February 28, 2003, except as to Note 2(L), which is as of May 9, 2003, and Notes 2(M) and 8, which are as of August 18, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 25 FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FirstEnergy Corp. is a registered public utility holding company that provides regulated and competitive energy services (see Results of Operations - Business Segments). International assets were acquired as part of FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU Capital, Inc. and its subsidiaries provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power, Inc. and its subsidiaries develop, own and operate generation facilities in foreign countries. Sales are planned but not pending for the remaining international assets (see Capital Resources and Liquidity). Regulated electric distribution services are provided in Ohio by wholly owned subsidiaries (Ohio electric utilities) - Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), and The Toledo Edison Company (TE). Regulated services are provided in Pennsylvania through wholly owned subsidiaries (Pennsylvania electric utilities) - Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec) and Pennsylvania Power Company (Penn) - a wholly owned subsidiary of OE. Jersey Central Power & Light Company (JCP&L) provides electric distribution services in New Jersey. Transmission services are provided in the franchise areas of the Ohio electric utilities and Penn by wholly owned subsidiary American Transmission Systems, Inc. Transmission services are provided by Met-Ed, Penelec and JCP&L in their respective franchise areas. The coordinated delivery of energy and energy-related products, including electricity, natural gas and energy management services, to customers in competitive markets is provided through a number of subsidiaries. Subsidiaries providing competitive services include FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG), MARBEL Energy Corporation and MYR Group, Inc (MYR). RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy determined that it was appropriate to restate its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003. The revisions reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2006 for OE, 2007 for TE and in 2009 for CEI. FirstEnergy and the Ohio utilities amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, versus the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. The amortization expense under the revised method (see Note 1) increased by $49.7 million for the three months and $82.1 million for the six months ended June 30, 2002. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued 26 prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant were recorded as regulatory assets because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $722 million (CEI - $611; TE - $111 million) associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS 142. The total above market lease obligation of $755 million (CEI - $457 million; TE - $298 million) associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization schedules for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI and 2007 for TE. RESULTS OF OPERATIONS FirstEnergy experienced a net loss in the second quarter of 2003 of $57.9 million, or loss of $(0.20) per share of common stock (basic and diluted), compared to net income of $207.9 million, or earnings of $0.71 per share of common stock (basic and diluted) in the second quarter of 2002. Results in the second quarter of 2003 included an after-tax charge of $67.4 million or $0.23 per share of common stock (basic and diluted) resulting from the abandonment of FirstEnergy's shares in Emdersa's parent company, GPU Argentina Holdings, Inc. on April 18, 2003. During the first six months of 2003, net income was $160.6 million, or basic earnings of $0.55 per share of common stock ($0.54 diluted), compared to $326.2 million, or earnings of $1.11 per share of common stock (basic and diluted) in the first half of 2002. Net income in the first half of 2003 included a $60.5 million after-tax charge for discontinued operations in Argentina and an after-tax credit of $102.1 million resulting from the cumulative effect of an accounting change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Income before discontinued operations and the cumulative effect of an accounting change was $9.5 million, or $0.03 per share of common stock (basic and diluted) in the second quarter and $119.0 million, or basic earnings of $0.41 per share of common stock ($0.40 diluted) in the first six months of 2003. Results in the second quarter of 2003 were adversely affected by mild weather which reduced revenues after benefiting from unusually cold weather earlier in the year. Expenses in both periods were higher due to a $158.5 million charge for costs disallowed in the JCP&L rate case decision (see State Regulatory Matters - New Jersey), replacement power and additional nuclear expenses related to the extended outage at the Davis-Besse Nuclear Power Station (see Davis-Besse Restoration) and additional unplanned work performed during two nuclear refueling outages in the second quarter of 2003. Incremental costs of the extended outage at Davis-Besse reduced basic and diluted earnings per share of common stock by $0.13 in the second quarter and $0.30 in the first six months of 2003, compared to $.09 for both corresponding periods of 2002. Higher employee benefit expenses also contributed to increased costs in the second quarter and first six months of 2003 compared to the corresponding periods last year. However, the absence in the first six months of 2003 of the unusual charges incurred in the corresponding period of 2002 partially offset the higher costs in 2003. Reclassifications of Previously Reported Income Statement FirstEnergy recorded an increase to income during the six months ended June 30, 2002 of $31.7 million (net of income taxes of $13.6 million) relative to its decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified as part of normal operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change to the Consolidated Statement of Income previously reported for the six months ended June 30, 2002 are reflected in the restatements shown in Note 1. In June 2002, the Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis on the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Therefore, revenues and expenses for the second quarter and first six months of 2002 have been reclassified (see Implementation of Accounting Standard). 27 In April 2003, FirstEnergy divested its ownership of Emdersa -- see Note 3. As part of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million. The charge does not include the anticipated 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. Discontinued operations for the six-month period of 2003 totaled $60.5 million and included $6.9 million of after-tax earnings from the Argentina operation from the first quarter of 2003 - previously reported as $10.7 million of revenue, $0.1 million of expenses and $3.7 million of income taxes. Revenues Total revenues decreased $35.4 million in the second quarter of 2003, compared to the same period last year, primarily due to lower retail regulated electric sales and reduced international sales reflecting the May 2002 sale of a 79.9% interest in Avon. Increased revenues from competitive services, primarily electric sales to wholesale customers, partially offset the decrease in regulated electric retail and international revenues in the second quarter of 2003. In the first six months of 2003, revenues increased $345.1 million compared to the same period of 2002 from increased regulated and competitive sales, offset in part by reduced international sales from the partial sale of Avon. Sources of changes in revenues during the second quarter and first six months of 2003 compared to the corresponding periods of 2002 are summarized in the following table:
SOURCES OF REVENUE CHANGES THREE MONTHS SIX MONTHS ------------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) Electric Utilities (Regulated Services): Retail electric sales................. $ (151.2) $ (43.0) Wholesale electric sales ............. 39.2 178.8 All other revenues.................... (15.8) (2.4) ------------------------------------------------------------------- Total Electric Utilities................. (127.8) 133.4 ------------------------------------------------------------------ Unregulated Businesses (Competitive Services): Retail electric sales................. 48.3 115.0 Wholesale electric sales.............. 195.8 429.5 Gas sales............................. (32.1) 11.8 FSG................................... (51.5) (93.9) MYR................................... (25.7) (53.2) Other................................. 15.3 21.8 ------------------------------------------------------------------ Total Unregulated Businesses............. 150.1 431.0 ------------------------------------------------------------------ International............................ (70.3) (243.3) Other.................................... 12.6 24.0 ------------------------------------------------------------------ Net Change in Revenue.................... $ (35.4) $ 345.1 ==================================================================
Electric Sales Retail sales by FirstEnergy's electric utility operating companies (EUOC) decreased by $151.2 million in the second quarter of 2003 and by $43.0 million in the first six months of 2003 from the corresponding periods of 2002. Changes in electric generation kilowatt-hour sales and distribution deliveries in the second quarter and first six months of 2003 from the same periods of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES THREE MONTHS SIX MONTHS --------------------------------------------------------------------------------- INCREASE (DECREASE) Electric Generation Sales: Retail - Regulated services....................... (10.8)% (4.4)% Competitive services..................... 62.8% 90.2% Wholesale.................................. 130.1% 135.8% --------------------------------------------------------------------------------- Total Electric Generation Sales.............. 15.9% 23.2% ================================================================================= EUOC Distribution Deliveries: Residential................................ (5.6)% 5.6% Commercial................................. (0.3)% 5.5% Industrial................................. (2.6)% (0.8)% ---------------------------------------------------------------------------------- Total Distribution Deliveries................ (2.8)% 3.3% =================================================================================
28 Reduced air-conditioning load due to cooler-than-normal temperatures, continued sluggishness in the economy and increased sales by alternative suppliers all combined to decrease regulated retail generation sales revenue by $107.9 million in the second quarter of 2003 compared to the same quarter of 2002. These factors also accounted for most of the $112.6 million decrease in retail generation sales revenue in the first half of 2003 compared to the same period last year. Kilowatt-hour sales of electricity by alternative suppliers in FirstEnergy's franchise areas increased by 7.1 percentage points in the second quarter and 6.4 percentage points in the first half of 2003 from the corresponding periods last year. Revenues from distribution deliveries decreased by $32.8 million or 2.7% in the second quarter of 2003 compared to the second quarter of 2002 due in part to cooler-than-normal temperatures which reduced the air-conditioning load of residential and commercial customers. Weather also contributed to the $99.4 million (5.6%) increase in distribution deliveries to residential and commercial customers in the first half of 2003 from the same period last year. Temperatures ranged from 20% to 30% colder in the first three months of 2003 than the same period last year adding to heating-related loads. Sluggish economic conditions in both the second quarter and first half of 2003 contributed to reduced distribution deliveries to industrial customers from the corresponding periods last year. Further contributing to the decrease in retail electric revenues were Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $10.4 million of additional credits in the second quarter and $24.8 million of credits in the first half of 2003 compared to the same periods in 2002. These reductions in revenue are deferred for future recovery under the Ohio transition plan and do not materially affect current period earnings. EUOC sales to wholesale customers increased by $39.2 million in the second quarter and $178.8 million in the first six months of 2003, from the same periods last year. Substantially all of those increases resulted from the auction of JCP&L's basic generation service (BGS) responsibility to alternative suppliers. At the direction of the New Jersey Board of Public Utilities (NJBPU), JCP&L is selling its pre-existing sources of power supply, including energy provided by non-utility generation (NUG) contracts, into the wholesale market. Electric generation sales by FirstEnergy's competitive segment increased $244.1 million in the second quarter and $544.5 million in the first six months of 2003 from the corresponding periods of 2002, primarily from additional sales to the wholesale market ($195.8 million in the second quarter and $429.5 million in the first half of 2003). The increases resulted principally from sales into the New Jersey market as FES began supplying a portion of that state's BGS in September 2002. Retail sales by FirstEnergy's competitive services segment increased by $48.3 million in the second quarter and $115.0 million in the first six months of 2003 from the same periods of 2002. The increases primarily resulted from retail customers within FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity choice program. FirstEnergy's regulated and unregulated subsidiaries record purchase and sale transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three and six months ended June 30, 2003 and 2002 are summarized as follows:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, 2003 2002 2003 2002 ------------------------------------------------------------------- (IN MILLIONS) Sales................ $206 $ 35 $544 $67 Purchases............ 225 117 579 197 -------------------------------------------------------------------
FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell in the wholesale market. Nonelectric Sales Nonelectric sales revenues of the competitive services segment declined by $94.0 million in the second quarter and $113.4 million in the first six months of 2003 from the corresponding periods of 2002. The reduced revenues from FSG reflected the divestiture in early 2003 of its Colonial Mechanical and Webb Technologies subsidiaries (accounting for the majority of the decreases), as well as declines associated with weak economic conditions. MYR also experienced revenue reductions resulting from the sluggish economic environment. Natural gas sales were $32.1 million lower in the second quarter of 2003, but increased $11.8 million in the year-to-date period from the corresponding periods last year. Trends from 29 the first quarter of 2003 continued into the second quarter with higher unit prices and reduced volumes. However, the reduction in gas sales volumes accelerated in the second quarter of 2003 as FES focused its operations in a narrower geographic area and on higher margin gas customers which resulted in a decline in sales volume that more than offset the effect of higher gas costs. International Revenues International revenues declined $70.3 million in the second quarter and $243.3 million in the first six months of 2003 from the corresponding periods last year due to the sale of a 79.9% interest in Avon during the second quarter of 2002 and the subsequent application of equity accounting to FirstEnergy's remaining 20.1% interest. As a result, no revenues were recorded for FirstEnergy's equity interest in Avon in the second quarter and first six months of 2003. Expenses Total expenses increased $357.4 million in the second quarter and $819.6 million in the first six months of 2003 from the same periods of 2002. Sources of changes in expenses in the second quarter and first six months of 2003 compared to the corresponding periods of 2002 are summarized in the following table:
SOURCES OF EXPENSE CHANGES THREE MONTHS SIX MONTHS -------------------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) Fuel and purchased power.............. $355.3 $ 884.1 Purchased gas......................... (17.3) 5.9 Other operating expenses.............. (7.1) (118.7) Depreciation and amortization......... 8.6 24.1 General taxes......................... 17.9 24.2 -------------------------------------------------------------------------- NET INCREASE IN EXPENSES................ $357.4 $ 819.6 ==========================================================================
The increases in expenses in the second quarter and first six months of 2003 compared to the same periods of 2002 resulted from increased purchased power costs - $375.2 million higher in the second quarter and $910.4 million higher in the first six months of 2003. The higher costs resulted from $152.5 million of purchased power costs disallowed in the JCP&L rate case decision (see State Regulatory Matters - New Jersey), additional volumes to cover supply obligations assumed by FES for BGS sales to the New Jersey market, as well as other wholesale commitments, and additional supplies required to replace reduced nuclear generation. The combined effect of the extended Davis-Besse outage and additional unplanned work performed during the refueling outages at the Perry Plant and Beaver Valley Unit 1 reduced nuclear generation by 33.5% in the second quarter and 24.6% in the first six months of 2003 from the corresponding periods last year. Fuel expenses were $19.9 million and $26.4 million lower in the second quarter and first half of 2003, respectively, from the same periods of 2002, primarily reflecting reduced generation. Purchased gas costs decreased by $17.3 million in the second quarter of 2003 compared to the same period of 2002 due to lower volumes purchased to meet reduced sales levels, partially offset by higher unit costs. Other operating expenses decreased $7.1 million in the second quarter of 2003 compared to the same period of 2002, primarily due to reduced business volume from domestic energy-related businesses ($75.7 million) and decreased international expenses as a result of the sale of Avon ($31.1 million). The reduced volume of energy-related business reflects the sale in early 2003 of Colonial Mechanical and Webb Technologies businesses ($30.3 million), as well as continued declines associated with weak economic conditions. Partially offsetting these lower expenses were increased costs resulting from the Davis-Besse extended outage, unplanned work performed during the refueling outages at the Perry Plant and Beaver Valley Unit 1 in the second quarter of 2003, higher administration and general costs of $43.8 million (principally employee benefit costs - see Employee Benefit Plan Costs) and a $12.6 million impairment of a note receivable related to the sale of 79.9% of Avon. Nuclear nonfuel operating costs in the second quarter of 2003 were $61.7 million higher, including $10.3 million of additional incremental expense from the Davis-Besse extended outage. In the first six months of 2003, other operating expenses decreased $118.7 million as a result of the same factors which influenced the second quarter comparison: reduced business volume from domestic energy-related businesses ($141.8 million) and decreased international expenses as a result of the sale of Avon ($103.8 million). The sale of Colonial and Webb reduced expenses by $57.8 million in the first six months of 2003 compared to the same period of 2002. The absence of unusual charges recorded in the first six months of 2002 resulted in a further net reduction of other operating expenses ($59.4 million) from the corresponding period last year. Offsetting a portion of these lower expenses in the first half of 2003 were increased nuclear costs resulting from the extended Davis-Besse outage, unplanned work performed during the refueling outages in the second quarter of 2003 and higher administrative and general costs of $133.4 million (principally employee benefit costs). Nuclear nonfuel operating costs increased $88.1 million in the first six months of 2003 from the same period of 2002, including $46.5 million of additional incremental expense related to the Davis-Besse extended outage. 30 Charges for depreciation and amortization increased by $8.6 million in the second quarter of 2003 compared to the corresponding three-month period of 2002. The higher charges primarily resulted from five factors - increased amortization of the Ohio transition regulatory assets ($17.9 million), recognition of depreciation on four power plants ($10.0 million) which had been held pending sale in the second quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002, costs of $6.0 million disallowed in the JCP&L rate case decisions (see State Regulatory Matters - New Jersey) and reduced regulatory asset deferrals in 2003 ($7.1 million). Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals in Ohio ($10.4 million), lower charges resulting from the implementation of SFAS 143 ($11.5 million) and revised service life assumptions for generating plants ($6.5 million). In the first six months of 2003, depreciation and amortization increased $24.1 million as a result of the same factors which influenced the second quarter comparison - increased amortization of the Ohio transition regulatory assets ($42.1 million), recognition of depreciation on four power plants ($19.6 million) which had been held pending sale in the first half of 2002, costs of $6.0 million disallowed in the JCP&L rate case decision and reduced regulatory asset deferrals in 2003 ($15.0 million). Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals in Ohio ($24.8 million), lower charges resulting from the implementation of SFAS 143 ($26.0 million) and revised service life assumptions for generating plants ($12.7 million). General taxes increased $17.9 million in the second quarter and $24.2 million in the first six months of 2003 compared to the same periods last year. Higher payroll and kilowatt-hour taxes in 2003 and a $9 million energy assessment credit adjustment that reduced general taxes in the second quarter of 2002 were the principal factors contributing to the increases. Net Interest Charges Net interest charges decreased $44.4 million in the second quarter and $117.1 million in the first six months of 2003 compared to the same periods of 2002, due to previous debt and preferred stock redemptions and refinancing activities and the sale of a 79.9% interest in Avon in 2002. Redemption and refinancing activities during the first six months of 2003 totaled $415 million and $835 million (including $213 million of pollution control note repricings), respectively, and are expected to result in annualized savings of approximately $47 million. Partially offsetting these savings are interest charges on additional borrowings under revolving bank credit facilities. FirstEnergy also exchanged existing fixed-rate payments on outstanding debt (principal amount of $550 million as of June 30, 2003) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $7.8 million in the second quarter and $14.6 million in the first six months of 2003, compared to the corresponding periods of 2002 as a result of the lower variable rates paid under these agreements. FirstEnergy also closed out $168.5 million (notional amount) of interest rate swap transactions in the second quarter of 2003 and recognized gains of $5.7 million. Discontinued Operations On April 18, 2003, FirstEnergy divested its ownership in Emdersa. The abandonment was accomplished by relinquishing FirstEnergy's shares of Emdersa's parent company, GPU Argentina Holdings, to that company's independent Board of Directors, relieving FirstEnergy of all rights and obligations relative to this business. As a result of this action, FirstEnergy's gains and losses related to discontinuing these operations have been presented as a separate item on the Consolidated Statements of Income - "Discontinued operations" - in accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Due to the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million in the second quarter of 2003. This charge resulted from realizing $89.8 million of currency translation losses through current period earnings, partially offset by a $22.4 million gain recognized from eliminating FirstEnergy's investment in Emdersa. Discontinued operations for the six-month period reflected a net after-tax charge of $60.5 million, which included $6.9 million of earnings from Emdersa in the first quarter of 2003. As a result of the abandonment, FirstEnergy has substantially divested all of GPU Capital's international operations. Cumulative Effect of Accounting Change Results for the first six months of 2003 include an after-tax credit to net income of $102.1 million recorded upon the adoption of SFAS 143 in January 2003 (see discussion below). FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant and two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The asset retirement obligation (ARO) liability at the date of adoption was $1.109 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on decommissioning trust funds of $12 million. FirstEnergy expects substantially all of its nuclear decommissioning costs for 31 Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $174.6 million increase to income, or $102.1 million net of income taxes. Earnings Effect of SFAS 143 In June 2001, the FASB issued SFAS 143. That statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. In the second quarter and first six months of 2003, application of SFAS 143 (excluding the cumulative adjustment recorded upon adoption - see Note 5 ) resulted in the following changes to income and expense categories:
ENDED JUNE 30, 2003 ------------------------------------------------------------------------------------- EFFECT OF SFAS 143 THREE MONTHS SIX MONTHS ------------------------------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) Other operating expense Cost of removal (previously included in depreciation) $ 0.1 $ 4.3 Depreciation Elimination of decommissioning expense............... (22.3) (44.7) Depreciation of asset retirement cost................ 0.3 2.2 Accretion of asset retirement liability.............. 10.5 20.4 Reclassification of cost of removal to expense ...... -- (3.9) ----------------------------------------------------------------------------------- Net decrease to depreciation......................... (11.5) (26.0) ----------------------------------------------------------------------------------- Other Income Earnings on decommissioning trust balances........... 0.7 3.2 ---------------------------------------------------------------------------------- Income taxes......................................... 4.9 10.2 ---------------------------------------------------------------------------------- Net income effect.................................... $ 7.2 $ 14.7 ==================================================================================
Employee Benefit Plan Costs Sharp declines in equity markets since the second quarter of 2000 and a reduction in FirstEnergy's assumed discount rate for pensions and other post-employment benefit (OPEB) obligations have combined to produce a significant increase in those costs. Also, increases in health care payments and a related increase in projected trend rates have led to higher health care costs. Combined, these employee benefit expenses increased by $44.6 million in the second quarter and $93.8 million in the first six months of 2003 compared to the same periods in 2002. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months and six months ended June 30, 2003 and 2002.
THREE MONTHS ENDED SIX MONTHS ENDED PENSION AND OPEB EXPENSE (INCOME) JUNE 30, JUNE 30, -------------------------------------------------------------------------------------- 2003 2002 2003 2002 --------------------------------------------- (IN MILLIONS) Pension............................ $27.4 $(0.7) $ 58.7 $ (4.5) OPEB............................... 38.5 22.0 79.0 48.4 -------------------------------------------------------------------------------------- Total..............................$65.9 $21.3 $137.7 $43.9 ======================================================================================
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. 32 RESULTS OF OPERATIONS - BUSINESS SEGMENTS FirstEnergy manages its business as two separate major business segments - regulated services and competitive services. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated domestic transmission and distribution systems. It also provides generation services to franchise customers who have not chosen an alternative generation supplier. The Ohio electric utilities and Penn obtain generation through a power supply agreement with the competitive services segment (see Outlook - Business Organization). The competitive services segment also supplies a substantial portion of the "provider of last resort" (PLR) requirements for Met-Ed and Penelec through a wholesale contract. The competitive services segment includes all competitive energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy services such as heating, ventilation and air-conditioning. Financial results discussed below include intersegment revenues. A reconciliation of segment financial results to consolidated financial results is provided in Note 6 to the consolidated financial statements. Regulated Services Net income decreased to $107.0 million in the second quarter of 2003, compared to $247.5 million in the second quarter of 2002. In the first six months of 2003, net income decreased to $424.1 from $447.2 million in the first six months of 2002. The factors contributing to the changes in net income are summarized in the following table:
REGULATED SERVICES THREE MONTHSSIX MONTHS ------------------------------------------------------------------------------ INCREASE (DECREASE) (IN MILLIONS) Revenues...................................... $(130.5) $ 101.0 Expenses...................................... 149.6 408.4 ------------------------------------------------------------------------------ Income Before Interest and Income Taxes....... (280.1) (307.4) Net interest charges.......................... (23.6) (59.5) Income taxes.................................. (116.0) (123.8) ------------------------------------------------------------------------------- Decrease in Income Before Cumulative Effect of a Change in Accounting.......................... (140.5) (124.1) Cumulative effect of a change in accounting... -- 101.0 ------------------------------------------------------------------------------ Net Income Decrease........................... $(140.5) $ (23.1) ==============================================================================
Lower generation sales and distribution deliveries combined to decrease external electric revenues by $112.0 million in the second quarter of 2003 compared to the same quarter of 2002. Cooler than normal temperatures and a continued sluggish economy reduced sales in the second quarter. Retail generation sales were also adversely affected by additional kilowatt-hour sales by alternative suppliers in the FirstEnergy franchise area. The remaining change in sales primarily resulted from a decrease in energy-related revenues. Revenues in the first six months of 2003 increased $101.0 million from the same period last year due to a stronger first quarter performance in 2003 due in part to colder than normal weather compared to the same period in 2002. Expenses increased in the second quarter and first six months of 2003 from the corresponding periods of 2002. The increase in expenses in the second quarter of 2003 resulted principally from a $117.8 million increase in purchased power costs resulting from a $152.5 million charge related to the JCP&L rate case. Additional factors included an $18.4 million increase in other operating expenses, $8.1 million increase in depreciation and amortization expense and $6.5 million increase in general taxes. In the first six months of 2003, expenses increased $408.4 million from the same period of 2002. The increase in expenses resulted principally from a $344.4 million increase in purchased power costs due to higher sales to wholesale generation customers and the charge resulting from the JCP&L rate case. The other expense factors in the first six months of 2003 compared to the first six months of 2002 include a $32.4 million increase in other operating expense, $24.7 million increase in depreciation and amortization expense and $9.4 million increase in general taxes. Other operating expenses in both the second quarter and first six months of 2003 increased in part due to additional employee benefit costs from the corresponding periods of 2002. Depreciation and amortization expenses increased in the second quarter and first six months of 2003 from the same periods last year due principally to four factors - increased amortization of the Ohio transition regulatory assets, recognition of depreciation on four power plants which had been pending sale in the second quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002, the write-off of disallowed costs in the JCP&L rate case and the termination of regulatory asset deferrals in February 2003. Partially offsetting these increases in depreciation and amortization were higher shopping tax incentive deferrals in Ohio and lower charges resulting from the implementation of SFAS 143, including revised service life assumptions for generating plants. 33 Competitive Services Net losses increased to $44.0 million in the second quarter and $98.7 million in the first six months of 2003, compared to net income of $6.4 million and a net loss of $53.3 million in the corresponding periods of 2002. The factors contributing to the increased losses are summarized in the following table:
COMPETITIVE SERVICES THREE MONTHS SIX MONTHS ----------------------------------------------------------------------- INCREASE (DECREASE) (IN MILLIONS) Revenues................................... $304.8 $674.7 Expenses................................... 387.5 741.4 ----------------------------------------------------------------------- Income Before Interest and Income Taxes.... (82.7) (66.7) ------------------------------------------------------------------------ Net interest charges....................... 3.1 4.1 Income taxes............................... (35.4) (24.2) ------------------------------------------------------------------------ Decrease in Income Before Cumulative Effect of a Change in Accounting................... (50.4) (46.6) Cumulative effect of a change in accounting -- 1.2 ------------------------------------------------------------------------- Net Income................................. $(50.4) $(45.4) ========================================================================
The increase in revenues in the second quarter and first six months of 2003, compared to the corresponding periods of 2002, includes the net effect of several factors. Revenues from the electric wholesale market increased $195.8 million in the second quarter and $429.5 million in the first six months of 2003 from the same periods last year as kilowatt-hour sales more than doubled resulting principally from sales as an alternative supplier for a portion of New Jersey's BGS requirements. Retail kilowatt-hour sales revenues increased $48.3 million in the second quarter and $115.0 million in the first six months of 2003 from the same periods last year as a result of expanding the FES business in Ohio under Ohio's electricity choice program. Internal sales to the regulated services segment increased $154.6 million in the second quarter and $244.9 million in the first six months of 2003 compared to the same periods of 2002 primarily reflecting sales to Met-Ed and Penelec in supplying a substantial portion of their PLR requirements in Pennsylvania. Several factors partially offset the increase in revenues. Energy-related services such as heating, ventilation and air-conditioning work reflected the divestiture in early 2003 of Colonial and Webb, as well as continued declines associated with weak economic conditions. Revenues from energy-related services decreased $77.2 million in the second quarter and $147.1 million in the first six months of 2003 from the corresponding periods of 2002. Natural gas sales decreased $32.1 million in the second quarter, but increased $11.8 million in the first six months of 2003 from the corresponding periods last year. Gas revenue trends in the first quarter of 2003 continued into the second quarter with higher unit prices and reduced volumes. However, the reduction in gas sales volumes accelerated in the second quarter of 2003 as FES focused its operations to a narrower geographic area and on higher-margin gas customers with a resulting decline in volume that more than offset the effect of higher prices. Expenses increased $387.5 million in the second quarter and $741.4 million in the first six months of 2003 from the same periods of 2002 due to purchased power costs, which increased $400.8 million in the second quarter and $810.9 million in the first six months of 2003. The increases reflected the higher sales combined with reduced internal generation. Expenses of energy-related businesses declined $75.7 million in the second quarter and $141.8 million in the first six months of 2003 from the corresponding periods last year as a result of the divestiture of Colonial and Webb, as well as continued declines associated with weak economic conditions. Other operating expenses increased $99.0 million in the second quarter and $73.4 million in the first six months of 2003 from the corresponding periods of 2002. Additional costs resulting from the Davis-Besse extended outage, unplanned work performed during two nuclear refueling outages in the second quarter of 2003 and higher employee benefit costs all contributed to the increase in other operating expenses. The absence of unusual charges recorded in 2002 moderated the increase in operating expenses by $59.4 million in the year-to-date period of 2003 compared to the corresponding period of 2002. Purchased gas costs decreased $17.3 million in the second quarter of 2003 compared to the second quarter of last year as a result of reduced volumes required for gas sales. CAPITAL RESOURCES AND LIQUIDITY FirstEnergy's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without materially increasing FirstEnergy's net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, FirstEnergy expects to meet its contractual obligations with cash from 34 operations. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.5 billion of revolving credit facilities. In the first six months of 2003, FirstEnergy received $485.0 million of cash dividends from its subsidiaries and paid $220.4 million in cash common stock dividends to its shareholders. There are no material restrictions on the payment of cash dividends by FirstEnergy's subsidiaries. As of June 30, 2003, FirstEnergy had $64.2 million of cash and cash equivalents, compared with $196.3 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the second quarter and first six months of 2003, compared with the corresponding periods of 2002 were as follows:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------------------------------------- OPERATING CASH FLOWS 2003 2002 2003 2002 ------------------------------------------------------------------------ (IN MILLIONS) Cash earnings (1)........ $ 515 $ 495 $867 $856 Working capital and other (493) (233) (383) (130) ------------------------------------------------------------------------ Total.................... $ 22 $ 262 $484 $726
(1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $240 million due to a $260 million change in funds used for working capital and a $20 million increase in cash earnings. The change in funds used for working capital primarily represents offsetting changes for receivables, sale and leaseback rent payments, and prepayments. Cash Flows From Financing Activities The following table provides details regarding security issuances and redemptions during the second quarter and first six months of 2003:
SECURITIES ISSUED OR REDEEMED THREE MONTHS SIX MONTHS ------------------------------------------------------------------- (IN MILLIONS) New Issues Senior Notes........................ $159 $ 409 Long-Term Revolving Credit.......... 230 280 Unsecured Notes..................... 333 331 ------------------------------------------------------------------- $722 $1,020 Redemptions First Mortgage Bonds................ $593 $ 633 Pollution Control Notes............. -- 50 Secured Notes....................... 222 333 ------------------------------------------------------------------ $815 $1,016 Short-term Borrowings, Net............ $190 $ (48) -------------------------------------------------------------------
Net cash used for financing activities increased by $6 million in the second quarter of 2003 from the second quarter of 2002. The increase in funds used for financing activities resulted from increased financing of $650 million that was exceeded by $656 million of additional redemptions and repayments during the second quarter of 2003 compared to the same period of 2002. FirstEnergy had approximately $1.045 billion of short-term indebtedness as of June 30, 2003 compared to $1.093 billion at the end of 2002. Available borrowing capability included $151 million under $1.5 billion revolving lines of credit and $59 million under bilateral bank facilities. As of June 30, 2003, OE, CEI, TE and Penn had the aggregate capability to issue $2.2 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. 35 JCP&L, Met-Ed and Penelec no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of June 30, 2003, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $737 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 $4.0 billion of preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. On March 17, 2003, FirstEnergy filed a registration statement with the U.S. Securities and Exchange Commission covering securities in the aggregate of up to $2 billion. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, or share purchase contracts and related share purchase units. On April 21, 2003, OE completed a $325 million refinancing transaction that included two tranches - $175 million of 4.00% five-year notes and $150 million of 5.45% twelve-year notes. The net proceeds were used to redeem approximately $220 million of outstanding OE first mortgage bonds having a weighted average cost of 7.99%, with the remainder used to pay down short-term debt. On May 22, 2003, JCP&L completed a $150 million refinancing transaction that included one tranche - 4.8% Senior Notes due 2018. The proceeds of this transaction were used in conjunction with short-term borrowing, to call and redeem $78 million of medium term notes with a weighted average interest cost of 8.35% and $125 million of JCP&L Capital's Monthly Income Preferred Securities (8.56%). In May and June of 2003, OE executed four fixed-to-floating interest rate swap agreements with notional values of $50 million each on underlying senior notes with an average fixed rate of 5.09%. Counterparties closed $168.5 million of FirstEnergy fixed-to-floating interest rate swap agreements in the second quarter of 2003 on which $5.7 million of gains were recognized. In July 2003, FirstEnergy executed a fixed-to-floating rate swap agreement with a fixed rate of 4.80% on an underlying senior note. Cash Flows From Investing Activities Net cash used for investing activities totaled $109 million in the second quarter and $226 million in the first six months of 2003, compared to net cash of $418 million and $196 million, respectively, used for investing activities for the same periods of 2002. The $309 million change in the second quarter of 2003 resulted from the absence of the Avon cash amount recognized in the first quarter of 2002 resulting from the reclassification from the "Assets Pending Sale" presentation to normal operations presentation (see Note 3), and decreased capital expenditures. In May 2003, FirstEnergy received $19 million from Aquila as its first annual installment payment on the note receivable FirstEnergy had as part of its 79.9 percent sale of Avon in May 2002. After receiving this payment, FirstEnergy sold the remaining balance of its note receivable in the secondary market and received $63.2 million in proceeds on July 28, 2003. On May 22, 2003, FirstEnergy reached an agreement to sell its remaining 20.1% interest in Avon to Scottish and Southern Energy. Under the terms of the agreement, FirstEnergy will receive approximately $14 million, subject to bondholder approval. The following table summarizes investments made in the second quarter and first six months of 2003 by FirstEnergy's regulated services and competitive services segments: 36
PROPERTY SUMMARY OF CASH USED FOR INVESTING ACTIVITIES ADDITIONS INVESTMENTS OTHER TOTAL SOURCES (USES) (IN MILLIONS) THREE MONTHS ENDED JUNE 30, 2003 Regulated Services........................ $ (37) (1) $(69) $ 32 $ (74) Competitive Services...................... (135) (2) 1 (22) (156) Other..................................... (28) 47 102 (5) 121 Eliminations.............................. -- -- -- -- -------------------------------------------------------------------------------------------- Total............................ $(200) $(21) $112 $(109) ============================================================================================= SIX MONTHS ENDED JUNE 30, 2003 Regulated Services........................ $(155) (1) $ 67 (3) $ 24 $(64) Competitive Services...................... (214) (2) 64 (4) (93) (243) Other..................................... (55) (30) 106 (5) 21 Eliminations.............................. -- -- 60 60 -------------------------------------------------------------------------------------------- Total............................ $(424) $ 101 $ 97 $(226) =============================================================================================
(1) Property additions to distribution facilities. (2) Property additions to generation facilities. (3) Net of several items from cash investments and NUG trust offset in part by investments in nuclear decommissioning trusts. (4) Sale of assets - includes Colonial and Webb sale. (5) Primarily a change in OCI from Emdersa abandonment (see Note 3). During the second half of 2003, capital requirements for property additions and capital leases are expected to be approximately $397 million, including $31 million for nuclear fuel. FirstEnergy has additional requirements of approximately $264 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On 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 or possible sale of assets. Key issues being monitored by S&P include the 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 continued capture of merger synergies. On August 11, 2003, S&P stated that a recent U.S. District Court ruling (see Environmental Matters below) with respect to the Sammis Plant is negative for FirstEnergy's credit quality. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." OTHER OBLIGATIONS Obligations not included on FirstEnergy's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant. As of June 30, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.5 billion. Also, CEI and TE continue to sell substantially all of their retail customer receivables, which provided $145 million of financing not included on the Consolidated Balance Sheet as of June 30, 2003. 37 GUARANTEES AND OTHER ASSURANCES As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and ratings contingent collateralization provisions. As of June 30, 2003, the maximum potential future payments under outstanding guarantees and other assurances totaled approximately $1.0 billion as summarized below:
MAXIMUM GUARANTEES AND OTHER ASSURANCES EXPOSURE (IN MILLIONS) ---------------------------------------------------------- FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1)...... $ 855.0 Financings (2)(3)........................... 63.2 ---------------------------------------------------------- 918.2 Surety Bonds.................................. 24.5 Rating-Contingent Collateralization (4)....... 106.8 ---------------------------------------------------------- Total Guarantees and Other Assurances....... $ 1,049.5 ==========================================================
(1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Includes parental guarantees of subsidiary debt and lease financing including FirstEnergy's letters of credit supporting subsidiary debt. (3) Issued for various terms. (4) Estimated net liability under contracts subject to rating-contingent collateralization provisions. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions. Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody's to trigger additional collateralization. MARKET RISK INFORMATION FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk FirstEnergy is exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of FirstEnergy's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. 38 The change in the fair value of commodity derivative contracts related to energy production during the second quarter and first six months of 2003 is summarized in the following table: INCREASE (DECREASE) IN THE FAIR VALUE OF COMMODITY DERIVATIVE CONTRACTS
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2003 JUNE 30, 2003 --------------------------- ---------------------------- NON-HEDGE HEDGE TOTAL NON-HEDGE HEDGE TOTAL --------- ----- ----- --------- ----- ----- (IN MILLIONS) CHANGE IN THE FAIR VALUE OF COMMODITY DERIVATIVE CONTRACTS Net asset at beginning of period....................... $66.4 $42.9 $109.3 $ 53.8 $24.1 $ 77.9 New contract value when entered........................ -- -- -- -- -- -- Change in value of existing contracts.................. (1.4) 9.2 7.8 15.8 37.4 53.2 Change in techniques/assumptions....................... -- -- -- -- -- -- Settled contracts...................................... 1.0 (16.6) (15.6) (3.6) (26.0) (29.6) ---------------------------- ------------------------------- Net asset at end of period (1)......................... 66.0 35.5 101.5 66.0 35.5 101.5 --------------------------- ------------------------------- NON-COMMODITY NET ASSETS AT END OF PERIOD: Interest Rate Swaps (2)............................. -- 13.2 13.2 -- 13.2 13.2 --------------------------- ------------------------------- NET ASSETS - DERIVATIVE CONTRACTS AT END OF PERIOD (3). $66.0 $ 48.7 $114.7 $ 66.0 $ 48.7 $114.7 =========================== =============================== IMPACT OF CHANGES IN COMMODITY DERIVATIVE CONTRACTS (4) Income Statement Effects (Pre-Tax)..................... $(0.9) $ -- $(0.9) $ (4.4) $ -- $ (4.4) Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)................ $ -- $ (7.4) $(7.4) $ -- $ 11.4 $ 11.4 Regulatory Liability................................ $ 0.5 $ -- $ 0.5 $ 16.6$ -- $ 16.6
(1) Includes $50.8 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or discount. (3) Excludes $28.7 million of derivative contract fair value decrease, as of June 30, 2003, representing FirstEnergy's 50% share of Great Lakes Energy Partners, LLC. (4) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. Derivatives are included on the Consolidated Balance Sheet as of June 30, 2003 as follows:
NON-HEDGE HEDGE TOTAL ---------------------------------------------------------------------- (IN MILLIONS) CURRENT- Other Assets...................... $ 19.6 $18.5 $ 38.1 Other Liabilities................. (28.2) (1.6) (29.8) NON-CURRENT- Other Deferred Charges............ 75.8 32.4 108.2 Other Deferred Credits............ (1.2) (0.6) (1.8) ---------------------------------------------------------------------- Net assets........................ $ 66.0 $48.7 $ 114.7 ======================================================================
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts by year are summarized in the following table:
SOURCE OF INFORMATION - FAIR VALUE BY CONTRACT YEAR 2003(1) 2004 2005 2006 THEREAFTER TOTAL ----------------------------------------------------------------------------------------------------------- (IN MILLIONS) Prices actively quoted(2)............. $7.3 $7.9 $ (0.1) $ -- $ -- $15.1 Other external sources(3)............. 12.2 18.4 11.1 -- -- 41.7 Prices based on models................ -- -- -- 6.9 37.8 44.7 ----------------------------------------------------------------------------------------------------------- TOTAL(4)........................... $19.5 $26.3 $11.0 $6.9 $37.8 $101.5 ===========================================================================================================
(1) For the last two quarters of 2003. 39 (2) Exchange traded. (3) Broker quote sheets. (4) Includes $50.8 million from an embedded option that is offset by a regulatory liability and does not affect earnings. 40 FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2003. Based on derivative contracts held as of June 30, 2003, an adverse 10% change in commodity prices would decrease net income by approximately $6.7 million during the next twelve months. Interest Rate Swap Agreements During the second quarter of 2003, FirstEnergy entered into fixed-to-floating interest rate swap agreements, as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, fixed interest rates and interest payment dates match those of the underlying obligations. The swap agreements consummated in the second quarter of 2003 are based on a notional principal amount of $200 million. As of June 30, 2003, the debt underlying FirstEnergy's $550 million notional amount of outstanding fixed-for-floating interest rate swaps had a weighted average fixed interest rate of 5.69%, which the swaps have effectively converted to a current weighted average variable interest rate of 2.32%. GPU Power (through a subsidiary) used existing dollar-denominated interest rate swap agreements in the first six months of 2003. The GPU Power agreements convert variable-rate debt to fixed-rate debt to manage the risk of increases in variable interest rates. GPU Power's swaps had a weighted average fixed interest rate of 6.68% as of June 30, 2003 and December 31, 2002. The following summarizes the principal characteristics of the swap agreements:
JUNE 30, 2003 DECEMBER 31, 2002 ---------------------------- ----------------------------- NOTIONAL MATURITY FAIR NOTIONAL MATURITY FAIR INTEREST RATE SWAPS AMOUNT DATE VALUE AMOUNT DATE VALUE -------------------------------------------------------------------- (DOLLARS IN MILLIONS) Fixed to Floating Rate (Fair value hedges) $200 2006 $ 6.5 50 2008 1.3 150 2015 (0.6) $444 2023 $15.5 150 2025 6.6 150 2025 5.9 Floating to Fixed Rate (Cash flow hedges) $ 10 2005 $(0.6) $ 16 2005 $(0.9) ----------------------------------------------------------------------------------------------
Equity Price Risk Included in FirstEnergy's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $623 million and $532 million as of June 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $62 million reduction in fair value as of June 30, 2003. OUTLOOK FirstEnergy continues to pursue its goal of being the leading regional supplier of energy and related services in the northeastern quadrant of the United States, where it sees the best opportunities for growth. Its fundamental business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional presence, key elements for its strategy are in place and management's focus continues to be on execution. FirstEnergy intends to provide competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to its core business. As FirstEnergy's industry changes to a more competitive environment, FirstEnergy has taken and expects to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. FirstEnergy's current focus includes: 1) returning Davis-Besse to safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio; 3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's cost structure; and 5) enhancing its credit profile and financial flexibility. Business Organization FirstEnergy's business is managed as two distinct operating segments - a competitive services segment and a regulated services segment. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. FirstEnergy expects the transfer of ownership of 41 EUOC non-nuclear generating assets to FGCO will be substantially completed by the end of the Ohio market development period in 2005. All of the EUOC power supply requirements for the Ohio Companies and Penn are provided by FES to satisfy their PLR obligations, as well as grandfathered wholesale contracts. State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the EUOCs' respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of the EUOCs varies. Those provisions include: - allowing the EUOC's electric customers to select their generation suppliers; - establishing PLR obligations to non-shopping customers in the EUOC's service areas; - allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; - itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the EUOC's electric generation businesses; and - continuing regulation of the EUOC's transmission and distribution systems. Regulatory assets are costs that the respective regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. Regulatory assets declined by $664.9 million to $8.1 billion as of June 30, 2003 from the balance as of December 31, 2002. Over one-half of the reduction in regulatory assets resulted from the costs disallowed in the JCP&L rate case decision and adoption of SFAS 143 by JCP&L, Met-Ed, Penelec and Penn. The regulatory assets of the individual companies are as follows:
REGULATORY ASSETS AS OF ------------------------------------------------ JUNE 30, DECEMBER 31, COMPANY 2003 2002 ------------------------------------------------ (IN MILLIONS) OE............... $1,689.9 $1,848.7 CEI.............. 1,148.3 1,191.8 TE............... 537.2 578.2 Penn............. 60.3 156.9 JCP&L............ 3,004.4 3,199.0 Met-Ed........... 1,091.0 1,179.1 Penelec.......... 557.4 599.7 ---------------------------------------------- Total............ $8,088.5 $8,753.4 ==============================================
Ohio FirstEnergy's transition plan (which FirstEnergy filed on behalf of its Ohio electric utilities) included approval for recovery of transition costs, including regulatory assets, as filed in the transition plan through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The approved plan also granted preferred access over FirstEnergy's subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 megawatts of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. In February 2003, the Ohio electric utilities were authorized increases in revenues aggregating approximately $50 million (OE - $41 million, CEI - $4 million and TE - $5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the respective transition cost recovery periods. 42 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 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 43 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. 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). Incremental costs associated with the extended Davis-Besse outage for the second quarter and first six months of 2003 and 2002 were as follows:
THREE MONTHS ENDED SIX MONTHS ENDED COSTS OF DAVIS-BESSE EXTENDED OUTAGE JUNE 30, JUNE 30 --------------------------------------------------------------------------------- 2003 2002 2003 2002 ---- ---- ---- ---- (IN MILLIONS) INCREMENTAL PRE-TAX EXPENSE Replacement power $41.1 $33.6 $ 93.4 $33.6 Maintenance 22.4 12.1 58.6 12.1 ---------------------------------------------------------------------------------- Total $63.5 $45.7 $152.0 $45.7 ================================================================================== CAPITAL EXPENDITURES $ 2.4 $12.0 $ 2.4 $12.0 ==================================================================================
It is anticipated that an additional $22 million in maintenance costs will be expended over the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer months of July and August. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. 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. 44 The Companies believe they are in compliance with the current SO(2) and nitrogen oxides (NO(x)) reduction requirements under the Clean Air Act Amendments of 1990. SO(2) reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO(x) reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO(x) reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NO(x) Transport Rule imposes uniform reductions of NO(x) emissions (an approximate 85% reduction in utility plant NO(x) emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NO(x) emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NO(x) budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NO(x) budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NO(x) budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The civil complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures they may be required, may have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. Several EUOCs 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 June 30, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through the SBC. The Companies have total accrued liabilities aggregating approximately $53.8 million as of June 30, 2003. 45 The effects of compliance on the EUOCs with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. 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. Legal Matters It is FirstEnergy's understanding, as of August 18, 2003, five individual shareholder-plaintiffs have filed separate complaints against FirstEnergy alleging various securities law violations in connection with the restatement of earnings described herein. Most of these complaints have not yet been officially served on the Company. Moreover, FirstEnergy is still reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is, however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against it, the most significant of which are described above. IMPLEMENTATION OF ACCOUNTING STANDARD In June 2002, the EITF reached a partial consensus on Issue No. 02-03. Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis on the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation (see Note 5). In addition, the related kilowatt-hour sales and purchases statistics described above under Results of Operations were reclassified (1.4 billion kilowatt-hours in the second quarter and 2.7 billion kilowatt-hours in the first six months of 2002). The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations.
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ------------------------ ---------------------- IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES REVENUES EXPENSES --------------------------------------------------------------------------------------------------------- (IN MILLIONS) Total as originally reported....................... $2,949 $2,323 $5,842 $4,725 Adjustment......................................... (50) (50) (90) (90) ---------------------------------------------------------------------------------------------------------- Total as currently reported........................ $2,899 $2,273 $5,752 $4,635 =========================================================================================================
46 SIGNIFICANT ACCOUNTING POLICIES FirstEnergy prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of FirstEnergy's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. FirstEnergy's more significant accounting policies are described below. Purchase Accounting - Acquisition of GPU Purchase accounting requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities for GPU were based primarily on estimates. The more significant of these included the estimation of the fair value of the international operations, certain domestic operations and the fair value of the pension and other post-retirement benefit assets and liabilities. The purchase price allocations for the GPU acquisition were finalized in the fourth quarter of 2002. Regulatory Accounting FirstEnergy's regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine FirstEnergy is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which FirstEnergy operates, a significant amount of regulatory assets have been recorded - $8.1 billion as of June 30, 2003. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers 47 Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension and OPEB benefits are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the end of 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. Beginning in 2003, the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In developing FirstEnergy's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, FirstEnergy recognizes 48 a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur FirstEnergy would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill - fair value was higher than carrying value for each of its reporting units. The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. As of June 30, 2003, FirstEnergy had $6.3 billion of goodwill that primarily relates to its regulated services segment. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (FirstEnergy's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. 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 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods beginning before June 15, 2003, which continue to be applied based on their original effective dates. FirstEnergy is currently assessing the new standard and has not yet determined the impact on its financial statements. 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 immediately 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. 49 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. 50 PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) EXHIBITS FIRSTENERGY 15 Letter from independent public auditors 31.1 Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 31.2 Certification letter from chief financial officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 32.1 Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FirstEnergy has not filed as an exhibit to this Form 10-Q/A any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of the total assets of FirstEnergy and its subsidiaries on a consolidated basis, but hereby agrees to furnish to the Commission on request any such documents. (b) REPORTS ON FORM 8-K FIRSTENERGY- FirstEnergy filed fifteen reports on Form 8-K since March 31, 2003. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's divestiture of its Argentina operations through the abandonment of its investment resulting in a second quarter 2003 charge to net income of $63 million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information and a JCP&L rate proceeding update. A report dated May 9, 2003 reported that FirstEnergy had amended its Form 10-K for the year ended December 31, 2002 for a change in classification of a $57.1 million net of tax charge with no effect on previously reported net income. A report dated May 22, 2003 reported that FirstEnergy had reached an agreement to sell its remaining 20.1 percent interest in Avon. A report dated June 5, 2003 reported updated Davis-Besse information. A report dated June 11, 2003 reported that FirstEnergy subsidiaries, Met-Ed and Penelec, filed a letter with a Pennsylvania Public Utility Commission Administrative Law Judge which voids the 2001 settlement stipulation previously entered into by Met-Ed and Penelec. A report dated June 27, 2003 reported a JCP&L settlement agreement with all the parties in its base rate case proceeding except for the Board of Public Utilities Regulatory Staff and the Division of the Ratepayer Advocate. A report dated July 24, 2003 reported an updated Davis-Besse ready for restart schedule and cost estimates. A report dated July 25, 2003 reported the New Jersey Board of Public Utilities decision on JCP&L's rate proceedings. A report dated August 5, 2003 reported FirstEnergy's second quarter 2003 earnings results and other information. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated August 8, 2003 reported a U.S. District Court ruling with respect to the W. H. Sammis Plant under the Clean Air Act. A report dated August 28, 2003 reported FirstEnergy's financial status and liquidity. A report dated September 8, 2003 reported the announcement of a public offering of additional common stock and a Regulation G reconciliation of a non-GAAP financial measure, free cash flow, presented in connection with the offering. 51 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. September 11, 2003 FIRSTENERGY CORP. Registrant /s/ Harvey L. Wagner ----------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer 52