L-05-067, Letter Transmitting Firstenergy Corp. 2004 Annual Report
| ML051090392 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley, Davis Besse, Perry |
| Issue date: | 04/08/2005 |
| From: | Scilla R FirstEnergy Corp |
| To: | Dinitz I Office of Nuclear Reactor Regulation |
| References | |
| -RFPFR, BV-No. L-05-067, DB-Serial No.-3146, PY-CEI/NRR-2876L | |
| Download: ML051090392 (77) | |
Text
RrstEnergy, 76 South Main Steet Akron, Ohio 44308-1890 Randy Scilla Assistant Treasurer 330-384-5202 Fax: 330-364-3772 April 8, 2005 PY-CEI/NRR-2876L DB-Serial No.-3146 BV-No. L-05-067 Mr. Ira Dinitz U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D.C. 20555 Dear Mr. Dinitz; Re:
Docket Nos. 50-346, 50-440, 50-412, 50-334 Retrospective Premium Guarantee Enclosed you will find the 2004 FirstEnergy Corp. Annual Report. This is in addition to the 2005 Internal Cash Flow Projection sent March 8, 2005 and completes the requirements for the Retrospective Premium Guarantee.
Very truly yours, adp Enclosures
FirstEnergy
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Financial Highlights (Dollars in thousands, except per share amounts) 2004 2003 Total revenues
$12,453,046
$11,674,888 Income before discontinued operations and cumulative effect of accounting change'
$873,779
$424,249 Net income
$878,175
$422,764 Basic earnings per common share:
Before discontinued operations and cumulative effect of accounting change
$2.67
$1.40 After discontinued operations and cumulative effect of accounting change
$2.68
$1.39 Diluted earnings per common share:
Before discontinued operations and cumulative effect of accounting change
$2.66
$1.40 After discontinued operations and cumulative effect of accounting change
$2.67
$1.39 Dividends declared per common share`
S1.9125
$1.50 Book value per common share
$26.20
$25.35 Net cash from operations
$1,876,850
$1,754,855 The 2004 and 2003 discontinued operations are described in Note 2(J) to the Consolidated Financial Statements. The 2003 accounting change is described in Note 2(K) to the Consolidated Financial Statements.
A quarterly dividend of $0.4125 was declared in 2004 payable March 1. 2005, increasing the indicated annual dividend rate from $1.50 to $1.65 per share.
The following analysis reconciles basic earnings per share of common stock in 2004 and 2003 computed under generally accepted accounting principles (GAAP) to adjusted basic earnings per share excluding unusual items in both years (non GMP)*.
2004 2003 Adjusted basic earnings per share:
Basic earnings per share (GAAP)
$2.68
$1.39 Claim settlement (0.33)
Davis-Besse extended outage impacts 0.12 0.56 Rate case disallowance 0.36 Asset impairments 0.19 0.41
!Litigation settlement 0.03 Discontinued international operations 0.33 Cumulative effect of accounting change (0.33)
Other unusual items (see Management's Discussion) 0.01 0.03 Adjusted basic earnings per share (non-GAAP)
$3.03
$2.42 Generally, a non-GAAP financial measure is a numerical measure of a company's historical or future financial performance, financial position, or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in
- I accordance with GAAR Forward-Looking Statements This annual report includes forwardjooking 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), the receipt of approval from and entry of a final order by the U.S. District Court, Southern District of Ohio, on the pending settlement agreement resolving the New Source Review litigation and the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) related to this settlement, adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations, including by the Securities and Exchange Commission, the United States Attomey's Office and the Nuclear Regulatory Commission as disclosed in our Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage in particular, the availability and cost of capital, the continuing availability and operation of generating units, our inability to accomplish or realize anticipated benefits from strategic goals, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investigation into the causes of the August 14, 2003 regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. We expressly disclaim any current intention to update any forward4ooking statements contained herein as a result of new information, future events, or otherwise.
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To Shareholders We also delivered to shareholders a total annualized return - a measure of stock price appreciation plus reinvest-ed dividends - of 16.6 percent in 2004. This brings our five-year annualized total return to 17.1 percent, ranking us 17th among the 64 U.S. investor-owned electric utilities that comprise the Edison Electric Institute's (EEI) index.
Our performance and outlook supported your Board of Directors' action to increase the common stock dividend by 10 percent, the first increase since the Company was created in 1997.
Operational Results To support our ongoing focus on enhancing service reliability, last year we spent $940 million on capital improve-ment projects and operating and maintenance activities in our energy delivery area. In 2005, we expect to spend more than $1 billion, including expenditures on a wide range of system enhancements. Our plans include upgrading and renewing our transmission and distribution facilities, improving relaying and protection to minimize service interruptions, installing remote control and automation to ensure timely restoration when service interruptions occur, and adding new technologies such as advance lightning detection, which enables our system to better protect itself. We are investing in our critical infrastructure with the clear goal of strengthening our reliability and improving customer service.
In another effort to improve service reliability, we modified our existing information technologies to develop a leading-edge capability to track outage history down to the individual customer. Scheduled for full implementation in June 2005, this system can pinpoint locations and causes of prob-lems, enabling us to target our investments in improvements that enhance reliability and customer satisfaction.
W e
made significant progress in 2004.
We positioned ourselves for continued success in the years ahead and placed many of the challenges of the past several years behind us.
Our key accomplishments included:
- Returning the Davis-Besse Nuclear Power Station to safe and reliable operation
- Enhancing the reliability of our service to customers
- Achieving record performance by our generation fleet
- Gaining approval for our Rate Stabilization Plan in Ohio Our financial performance in 2004 was strong, particularly in the key areas of earnings, cash flow and debt reduction. We delivered basic earnings per share of
$2.91 on a non-GAAP* basis, exceeding our guidance to the financial community of $2.70 to $2.85. Net cash from operating activities also remained strong at $1.88 billion -
up from $1.75 billion in 2003 - and we met our target to reduce debt by $1 billion.
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Our storm restoration process proved its effectiveness in response to a major storm event in May of 2004, as well as during two ice storms this past winter. All three events caused interruptions to hundreds of thousands of customers.
Despite severe damage to our system, we restored service to all customers faster than at any time in our history, with 80 percent back in service within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
In addition to the storm process work at home, some 400 volunteer employees traveled to Florida and Alabama to assist in restoring service in the aftermath of the multi-ple hurricanes that ravaged those areas in 2004. Along with the hundreds of letters of thanks we received from grateful residents, we are proud that the hard work and dedication of our employees were further recognized by EEI, which named FirstEnergy a recipient of the EEI Emergency Assistance Award.
"Our financial performance in 2004 was strong, particularly in the key areas of earnings, cash flow and debt reduction."
18 billion KWH, topping its previous record by more than 2 billion KWH. Its 88.9 percent capacity factor - the actual amount of electricity generated compared with the amount that could be generated at full power for the year - placed its performance in the industry's top decile. In the fall of 2005, we expect to initiate the plant's first capacity expan-sion program with a planned upgrade of Unit 1's turbine, which should increase its output by about 50 MW. Similar upgrades are planned for units 2 and 3 in coming years, which would enable the plant to produce an additional 1 billion KWH annually.
Turning to our nuclear fleet, we completed a major reor-ganization of our FirstEnergy Nuclear Operating Company (FENOC) subsidiary that added experienced nuclear man-agers and centralized managerial oversight of our nuclear units; established a uniform organizational structure within the plants; and began implementing common procedures and practices across the fleet. The capacity factor of our nuclear fleet reached 90.6 percent, a historic high, even with Davis-Besse's return to service in March. Beaver Valley earned a Performance Improvement Award from the Institute of Nuclear Power Operations, and its Unit 2 has operated for more than 500 consecutive days, establishing a plant record for continuous operation. More important, the fleet posted a record low U.S. Occupational Safety and Health Administration (OSHA) Reportable Incident Rate, led by the Perry Plant, where employees have worked 8.9 million hours without a lost-time accident.
In 2004 and early 2005, we also reached multi-year labor agreements with 8 union locals representing more than 3,250 workers. Employees represented by these unions have joined our new health care plan, providing them with competitive benefits while enabling the Company to better manage the increasing costs of health care.
Another highlight of 2004 was the performance of our generation fleet, which produced a record 76 billion kilowatt-hours (KWH). The fossil generation fleet provided solid performance, producing more than 45 billion KWH, while our nuclear fleet produced a record 29.9 billion KWH.
Our largest coal-based generating facility, the 2,360-megawatt (MW) Bruce Mansfield Plant, led the way for our fossil fleet. The plant set a generation record of more than 3
We accomplished these solid results while maintaining our focus on safety. In 2004, we achieved a Company-wide OSHA rate of 1.44 incidents per 100 employees, a 9-percent reduction compared with 2003 results. This performance typically would rank us in the top decile of our industry, although EEI has not yet published results for 2004.
We expect to continue enhancing our operational performance under the leadership of our Executive Vice President and Chief Operating Officer, Richard R. Grigg, who joined the Company in August. With 34 years of industry experience, most recently as president and chief executive officer of WE Generation, Mr. Grigg leads our Energy Delivery, Fossil Generation and Commodity Operations business units.
Protecting the Environment We also delivered strong results in our efforts to protect the environment. Last year, 40 percent of our electricity was produced from our non-emitting nuclear fleet. We also achieved continuing emission reductions from our coal-based plants.
Since 1990, we've reduced nitrogen oxides (NOx) by more than 60 percent and sulfur dioxide (S02) by nearly one-half.
In the past three years, we've spent $196 million to install selective catalytic reduction equipment on all three units of our scrubber-equipped Bruce Mansfield Plant. This equipment is designed to reduce NOx emissions, a precursor to ozone, by more than 8,000 tons during the summer ozone season.
And, in March of this year, we announced plans to significantly reduce emissions of NOx and S02 from current levels at several of our power plants as part of a settlement agreement that resolves all issues related to the New Source Review case involving our W. H. Sammis Plant. Under the "Last year, 40 percent of our electricity was produced from our non-emitting nuclear fleet."
agreement, we will install additional environmental controls at Sammis, as well as at a number of our other power plants.
For example, in the fall of 2005, we will begin a three-year project to improve the existing scrubbers at the Mansfield Plant as part of our plans to further reduce S02 emissions.
The new environmental controls also will provide the foundation for achieving the emission reductions we will be making to comply with the U.S. Environmental Protection Agency's recently announced Clean Air Interstate and Clean Air Mercury rules.
We're working on the development of cost-effective, new technologies to help achieve these additional reductions. One promising new technology is the Electro-Catalytic Oxidation' TM (ECO) system developed by Powerspan Corp. and currently being demonstrated at our R. E. Burger Plant. This technology is designed to reduce NOx, SO2, fine particulates and mercury emissions, and, if successful, will be available for commercial application at coal-based power plants across the country.
Setting the Stage for the Future As a result of our successful efforts to reduce debt, control costs and enhance cash flow, your Board declared a new quarterly dividend of 41.25 cents per share of out-standing common stock, which represents a 10-percent increase over the previous quarterly rate. The new indicated annual dividend is $1.65 per share, up from $1.50 per share.
Your Board also adopted a dividend policy that targets sustainable annual dividend increases after 2005, generally reflecting an annual growth rate of 4 to 5 percent, and an earnings payout ratio generally within the range of 50 to 60 percent. The Board will continue to review FirstEnergy's dividend policy regularly. The amount and timing of all dividend payments are subject to the Board's consideration of business conditons, results of operations, financial condition and other factors.
We also enhanced the value of your investment by retiring, refinancing or restructuring more than $2.8 billion in long-term debt last year, which reduced interest costs by approximately $54 million in 2004.
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"We expect to fill approximately 1,600 positions system-wide in the next two years..."
The $1 billion in debt we eliminated brings the total to
$3 billion since 2002, reducing our adjusted debt-to-capital-ization ratio to 57 percent from 65 percent three years ago. At the same time, we were able to resolve funding issues related to our pension program for the next several years by making a $500-million contribution to the plan in September. Even so, the total capacity of our primary credit facilities stood at $2.3 billion at year-end.
Another significant accomplishment in 2004 - for our customers and for your Company - was gaining approval by the Public Utilities Commission of Ohio (PUCO) of our Rate Stabilization Plan. The plan will provide a longer period of predictable revenue from our three Ohio electric utility operating companies. In addition, it will provide customers with more stable generation prices for three years following the end of Ohio's market development period on December 31, 2005, under the state's electricity deregulation law. An independent auction conducted last fall at the direction of the PUCO confirmed that the price we offered under the plan was competitive.
We addressed another key challenge last year with an agreement that resolves all pending private securities and derivative lawsuits related to the extended outage at Davis-Besse; the August 14, 2003, regional power outage; and financial restatements related to changed accounting treat-ments for transition assets being recovered in Ohio. Four customer damage cases related to the regional power outage remain in various venues in Ohio and New York.
Preparing for Our Workforce of the Future We're also addressing a significant issue facing compa-nies throughout the U.S. - the need to replace experienced employees who will retire over the next several years. We expect to fill approximately 1,600 positions system-wide in the next two years alone - some through promotions and reassignments, but primarily through aggressive efforts to recruit talented and highly motivated people from outside our Company who will help ensure our future success.
The hiring will occur across the Company, including generating plant and utility workers, as well as an array of technical and professional positions.
Our business requires considerable skills and continu-ous attention to safety by our employees. We will work to ensure that new employees receive on-thejob training, as well as ongoing mentoring from the experienced and knowl-edgeable employees we're fortunate to have on staff now.
Building on Our Progress Executing our plan was critical to our progress in 2004, and will serve as a solid foundation for future growth.
Certainly, challenges remain. However, I'm confident that, through the hard work of our skilled and dedicated employees and your continued support, we will build on that progress and enhance the long-term value of your investment.
Sincerely, Anthony J. Alexander President and Chief Executive Officer March 18, 2005
' This letter to shareholders contains non-GAP earnings per share. This non-GMP measure excludes amounts that are not normally excluded in the most directly com-parable measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). A reconciliation of GAAP basic earnings per share ($2.68 in 2004) to nonGWP basic earnings per share ($3.03 in 2004, before the reduction of $0.12 per share for DavisBesse impacts) can be found in the accompanying Managements Discussion and Analysis of Results of operations and Financial Condition on page 13.
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FirstEnergy Board of Directors
Paul I. Addison Anthony J. Alexander O
n behalf of your Board of Directors, I would like to take this opportunity to thank our management team and all employ-ees for a year of significant progress and achievement.
During the year, your Board also took a number of steps to enhance our responsiveness to the shareholders we are privileged to serve.
For example, we reviewed and strengthened our overall corporate governance practices - taking steps that included updat-ing charters and policies, separating the functions of chairman and CEO, and eliminating staggered terms so that all directors will be elected annually when their current terms expire.
We also elected to eliminate the Shareholder Rights Plan - a move that a majority of our shareholders supported - and we agreed to put any future plan to a shareholder vote within one year of adoption.
These and other actions have helped make your Company a leader in an important corporate governance measurement devel-oped by Institutional Shareholder Services (ISS) - the Corporate Governance Quotient (CGQ). At year-end, our CGQ index ranking was 96.9, reflecting the percentage of companies in the S&P 500 Index we outperformed. Our industry ranking of 95.7 reflected our per-formance against companies in ISS's utility group.
In addition, we were pleased to raise your Company's common-stock dividend - the first increase since FirstEnergy was formed in 1997. And, we adopted a policy that should provide for dividend growth in the future.
On a more personal note, I join the Board in expressing our appreciation to recently retired Director John M. Pietruski for his many years of service to GPU, Inc., and FirstEnergy. Also, we welcome Ernest J. Novak, Jr., who was elected to the Board in May, and Wesley M. Taylor, who was elected in September. Mr. Novak, retired managing partner of the Cleveland office of Ernst & Young LLP, is serving as your Board's designated financial expert.
We are confident that these and other changes represent the best interests of our shareholders, and we appreciate your continued support as we consider new ways to enhance the value of your investment in FirstEnergy.
Sincerely, Cz r Paul J. Powers Catherine A. Rein Paul T. Addison, 58 Retired, formerly Managing Director in the Utilities Department of Salomon Smith Barney (Citigroup). Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2003.
Anthony J. Alexander, 53 President and Chief Executive Officer of FirstEnergy Corp. Director of FirstEnergy Corp. since 2002.
Dr. Carol A. Cartwright, 63 President, Kent State University.
Chair, Corporate Govemance Committee; Member, Compensation Committee.
Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.
William T. Cottle, 59 Retired, formerly Chairman of the Board, President and Chief Executive Officer of STP Nuclear Operating Company. Chair, Nuclear Committee; Member, Corporate Governance Committee. Director of FirstEnergy Corp.
since 2003.
George M. Smart Chairman of the Board 6
Dr. Carol A. Cartwright William T. Cottle Russell W. Maier Emest J. No~vak, Jr.
Robert N. Pokelwalrdt Robert C. Savage George M. Smart Wesley M. Taylor Jesse 1 Williams, Sr.
Dr. Patricia K. Woolf Russell W. Maier, 68 President and Chief Executive Officer of Michigan Seamless Tube LLC.
Member, Compensation and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1995-1997.
Ernest J. Novak, Jr., 60 Retired, formerly Managing Partner of the Cleveland office of Ernst & Young LLP. Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2004.
Robert N. Pokelwaldt, 68 Retired, formerly Chairman of the Board and Chief Executive Officer of YORK International Corporation.
Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 2000-2001.
Paul J. Powers, 70 Retired, formerly Chairman of the Board and Chief Executive Officer of Commercial Intertech Corp. Chair, Finance Committee; Member, Compensation Committee. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.
Catherine A. Rein, 62 Senior Executive Vice President and Chief Administrative Officer of Metropolitan Life Insurance Company.
Chair, Compensation Committee; Member, Audit Committee. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 1989-2001.
Robert C. Savage, 67 Chairman of the Board of Savage
& Associates, Inc. Member, Finance and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and of the former Centerior Energy Corporation from 1990-1997.
George M. Smart, 59 Non-executive Chairman of the FirstEnergy Board of Directors.
Retired, formerly President of Sonoco-Phoenix, Inc. Chair, Audit Committee. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1988-1997.
Wesley M. Taylor, 62 Retired, formerly President of TXU Generation. Member, Nuclear Committee. Director of FirstEnergy Corp. since 2004.
Jesse T. Williams, Sr., 65 Retired, formerly Vice President of Human Resources Policy, Employment Practices and Systems of The Goodyear Tire & Rubber Company.
Member, Corporate Governance and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.
Dr. Patricia K. Woolf, 70 Consultant, author, and former Lecturer in the Department of Molecular Biology at Princeton University. Member, Corporate Governance and Nuclear Committees. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 1983-2001.
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FirstEnergy Officers FirstEnergy Corp.
Anthony J. Alexander President and Chief Executive Officer Richard R. Grigg Executive Vice President and Chief Operating Officer Richard H. Marsh*
Senior Vice President and Chief Financial Officer Leila L. Vespoli*
Senior Vice President and General Counsel Harvey L. Wagner Vice President, Controller and Chief Accounting Officer David W. Whitehead Corporate Secretary Thomas C. Navin*
Treasurer Paulette R. Chatman*
Assistant Controller Jeffrey R. Kalata*
Assistant Controller Randy Scilla*
Assistant Treasurer Jacqueline S. Cooper*
Assistant Corporate Secretary Edward J. Udovich*
Assistant Corporate Secretary
' Also holds the same title with FirstEnergy Service Company, FirstEnergy Solutions Corp. and FirstEnergy Nuclear Operating Company FirstEnergy Service Company Anthony J. Alexander President and Chief Executive Officer Richard R. Grigg Executive Vice President and Chief Operating Officer Mark T. Clark Senior Vice President Douglas S. Elliott Senior Vice President Charles E. Jones Senior Vice President Kevin J. Keough Senior Vice President Carole B. Snyder Senior Vice President Thomas M. Welsh Senior Vice President David M. Blank Vice President Mary Beth Carroll Vice President Lynn M. Cavalier Vice President Kathryn W. Dindo Vice President and Chief Risk Officer Ralph J. DiNicola Vice President Michael J. Dowling Vice President and Chief Procurement Officer Bradley S. Ewing Vice President Terrance G. Howson Vice President All Jamshidl Vice President Mark A. Julian Vice President David C. Luff Vice President Stanley F. Szwed Vice President Bradford F. Tobin Vice President and Chief Information Officer Harvey L. Wagner Vice President and Controller David W. Whitehead Vice President, Corporate Secretary and Chief Ethics Officer Lisa S. Wilson Assistant Controller FirstEnergy Solutions Corp.
Guy L. Pipitone Alfred G. Roth Trent A. Smith Harvey L. Wagner David W. Whitehead President Vice President Vice President Vice President and Corporate Secretary Charles D. Lasky Donald R. Schneider Daniel V. Steen Controller Vice President Vice President Vice President FirstEnergy Nuclear Operating Company Anthony J. Alexander Joseph J. Hagan Mark B. Bezilla L. William Pearce Harvey L. Wagner Chief Executive Officer Senior Vice President Vice President, Vice President, Vice President Gary R. Leidich Lew W. Myers Davis-Besse Beaver Valley and Controller President and Chief Operating Officer Richard L. Anderson Jeanine M. Rinckel David W. Whitehead Chief Nuclear Officer Vice President, Perry Vice President, Corporate Secretary Oversight FirstEnergy Regional Operations Management Dennis M. Chack Regional President The Cleveland Electric Illuminating Company Thomas A. Clark Regional President Ohio Edison Company James M. Murray Regional President The Toledo Edison Company Stephen E. Morgan President Jersey Central Power
& Light Company Donald M. Lynch Regional President Jersey Central Power
& Light Company Steven E. Strah Regional President Jersey Central Power
& Light Company Ronald P. Lantzy Regional President Metropolitan Edison Company John E. Paganle Regional President Pennsylvania Electric Company 8
Glossary of Terms The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
ATSI American Transmission Systems, Inc., owns and operates transmission facilities Avon Avon Energy Partners Holdings CEI The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary CFC Centerior Funding Corporation, a wholly owned finance subsidiary of CEI Companies OE, CEI, TE. Penn, JCP&L, Met-Ed and Penelec Emdersa Empresa Oistribuidora Electrica Regional SA.
EUOC Electric Utility Operating Companies (OE. CEI. TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)
FENOC FirstEnergy Nuclear Operating Company, operates nuclear generating facilities FES FirstEnergy Solutions Corp., provides energy-related products and services FESC FirstEnergy Service Company, provides legal, financial, and other corporate support services FGCO FirstEnergy Generation Corp.. operates nonnuclear generating facilities FirstCom First Communications, LIC, provides local and long-distance telephone service FirstEnergy FirstEnergy Corp., a registered public utility holding company FSG FirstEnergy Facilities Services Group, LLC.
the parent company of several heating, ventilation, air conditioning and energy management companies GLEP Great Lakes Energy Partners, LIC, an oil and natural gas exploration and production venture GPU GPU. Inc.. former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001 GPU Capital GPU Capital, Inc.. owned and operated electric distribution systems in foreign countries GPU Power GPU Power, Inc.. owned and operated generation facilities in foreign countries JCP&L Jersey Central Power & Light Company. a New Jersey electric utility operating subsidiary MARBEL MARBEL Energy Corporation, previously held FirstEnergy's interest in GLEP Met-Ed Metropolitan Edison Company. a Pennsylvania electric utility operating subsidiary MYR MYR Group, Inc., a utility infrastructure construction service company NED Northeast Ohio Natural Gas Corp., formerly a MARBEL subsidiary GE Ohio Edison Company, an Ohio electric utility operating subsidiary Ohio Companies CEI, OE and TE Penelec Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary Penn Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE PNBV PNBV Capital Trust, a special purpose entity created by OE in 1996 Shippingport Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 TE The Toledo Edison Company, an Ohio electric utility operating subsidiary TEBSA Termobarranquilla SA.. Empresa de Servicios Publicos The following abbreviations and acronyms are used to identify frequently used terms in this report:
FIN FASB Interpretation FIN 46R FIN 46 Irevised December 2003). 'Consolidation of Variable Interest Entities' FMB First Mortgage Bonds FSP FASB Staff Position FSP EITF 03-1-1 FASB Staff Position No. EITF Issue 03-1-1. 'Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments' FSP 106-1 FASB Staff Position No.106-1, 'Accounting and Disclosure Requirements Related to the Medicare Prescription Drug. Improvement and Modernization Act of 2003' FSP 106-2 FASB Staff Position No.106-2, 'Accounting and Disclosure Requirements Related to the Medicare Prescription Drug. Improvement and Modernization Act of 2003' FSP 109-1 FASB Staff Position No. 109-1, 'Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Oualified Production Activities provided by the American Jobs Creation Act of 2004' GAAP Accounting Principles Generally Accepted in the United States HVAC Heating, Ventilation and Air-conditioning IRS Internal Revenue Service ISO Independent System Operator KWH Kilowatt-hours LOC Letter of Credit MACT Maximum Achievable Control Technologies Medicare Act Medicare Prescription Drug. Improvement and Modernization Act of 2003 MISO Midwest Independent System Transmission Operator, Inc.
Moody's Moody's Investors Service MTC Market Transition Charge MW Megawatts NAAOS National Ambient Air Ouality Standards NERC North American Electric Reliability Council NJBPU New Jersey Board of Public Utilities NOAC Northwest Ohio Aggregation Coalition NOV Notices of Violation NOx Nitrogen Oxide NRC Nuclear Regulatory Commission NUG Non-Utility Generation OCC Ohio Consumers' Counsel OCI Other Comprehensive Income OPEB Other Post-Employment Benefits PCAOB Public Company Accounting Oversight Board (United States)
PJM PJM Interconnection L.LC.
PLR Provider of Last Resort PPUC Pennsylvania Public Utility Commission PRP Potentially Responsible Party PUCO Public Utilities Commission of Ohio PUHCA Public Utility Holding Company Act RTC Regulatory Transition Charge S&P Standard & Poor's Ratings Service SBC Societal Benefits Charge SEC United States Securities and Exchange Commission SFAS Statement of Financial Accounting Standards SFAS 71 SFAS No. 71, 'Accounting for the Effects of Certain Types of Regulation' SFAS B7 SFAS No. 87, 'Employers' Accounting for Pensions' SFAS 101 SFAS No. 101, 'Accounting for Discontinuation of Application of SFAS 71' SFAS 106 SFAS No. 106, 'Employers' Accounting for Postretirement Benefits Other Than Pensions' SFAS 115 SFAS No. 115. 'Accounting for Certain Investments in Debt and Equity Securities' SFAS 123 SFAS No. 123. "Accounting for Stock-Based Compensation' SFAS 1231R) SFAS No. 123(R), 'Share-Based Payment' SFAS 131 SFAS No. 131, 'Disclosures about Segments of an Enterprise and Related Information' SFAS 133 SFAS No. 133, 'Accounting for Derivative Instruments and Hedging Activities' SFAS 140 SFAS No. 140, 'Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities' SFAS 142 SFAS No. 142, 'Goodwill and Other Intangible Assets' SFAS 143 SFAS No. 143, 'Accounting for Asset Retirement Obligations' SFAS 144 SFAS No. 144, 'Accounting for the Impairment or Disposal of Long-Lived Assets' SFAS 150 SFAS No. 150, 'Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity' SFAS 151 SFAS No. 151, 'Inventory costs -an amendment of ARB No. 43, Chapter 4' S02 Sulfur Dioxide TBC Transition Bond Charge TMI-1 Three Mile Island Unit 1 TMI-2 Three Mile Island Unit 2 VIE Variable Interest Entity AU AOCL APB APB 25 APB 29 ARB 43 ARO ASLB BGS CO2 CTC ECAR EITF EITF 03-1 EITF 03-16 EITF 974 EITF 99-19 EPA FASB FERC Administrative Law Judge Accumulated Other Comprehensive Loss Accounting Principles Board APB Opinion No. 25. "Accounting for Stock Issued to Employees" APB Opinion No. 29. "Accounting for Nonmonetary Transactions" Accounting Research Bulletin No. 43. "Restatement and Revision of Accounting Research Bulletins" Asset Retirement Obligation Atomic Safety and Licensing Board Basic Generation Service Carbon Dioxide Competitive Transition Charge East Central Area Reliability Coordination Agreement Emerging Issues Task Force EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" EITF Issue No. 03-16, "Accounting for Investments in Limited Liability Companies" EITF Issue No. 97-4 'Deregulation of the Pricing of Electricity -Issues Related to the Application of FASB Statements No. 71 and 101' EITF Issue No. 99-19. "Reporting Revenue Gross as a Principal versus Net as an Agent" Environmental Protection Agency Financial Accounting Standards Board Federal Energy Regulatory Commission FirstEnergy Corp. 2004 9
Management Reports Management's Responsibility for Financial Statements The consolidated financial statements were prepared by management who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company's 2004 consolidated financial statements.
FirstEnergy Corp.'s internal auditors, who are responsible to the Audit Committee of FirstEnergy's Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy's Audit Committee consists of five inde-pendent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee's findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company's independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the indepen-dent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews manage-ment's programs to monitor compliance with the Company's policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held six meetings in 2004.
Management's Report on Internal Control Over Financial Reporting Management is responsible for establishing and main-taining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework, management con-ducted an evaluation of the effectiveness of the Company's internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company's internal control over financial reporting was effec-tive as of December 31, 2004. Management's assessment of the effectiveness of the Company's internal control over financial reporting, as of December 31, 2004, has been audit-ed by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 11.
10 FirstEnergy Corp. 2004
Report of Independent Registered Public Accounting Firm To the Stockholders and Board of Directors of FirstEnergy Corp.:
We have completed an integrated audit of FirstEnergy Corp.'s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stock-holders' equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of FirstEnergy Corp. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these state-ments in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and per-form the audit to obtain reasonable assurance about whether the financial statements are free of material mis-statement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant esti-mates made by management, and evaluating the overall financial state-ment presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2(K) to the consolidated financial statements, the Company changed its method of accounting for asset retirement obliga-tions as of January 1, 2003. As discussed in Note 7 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003.
Internal control over financial reporting Also, in our opinion, management's assessment, included in the accompany-ing Management's Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of inter-nal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circum-stances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reason-able assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting princi-ples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
LL-A PricewaterhouseCoopers LLP Cleveland, Ohio, March 7, 2005 FirstEnergy Corp. 2004 11
SELECTED FINANCIAL DATA (in thousands, except per share amounts)
For the Years Ended December 31, 2004 2003 2002 2001 2000 Revenues S12,453,046
$11,674,888
$11,453,354
$ 7,237,011
$ 6,470,488 Income Before Discontinued Operations and Cumulative Effect of Accounting Changes
$ 873,779
$ 424,249
$ 618,385
$ 654,946
$ 598,970 Net Income
$ 878,175
$ 422,764
$ 552,804
$ 646,447
$ 598,970 Basic Earnings per Share of Common Stock:
Before Discontinued Operations and Cumulative Effect of Accounting Changes S
2.67 1.40 2.11 2.85 2.69 After Discontinued Operations and Cumulative Effect of Accounting Changes S
2.68 1.39 1.89 2.82 2.69 Diluted Earnings per Share of Common Stock:
Before Discontinued Operations and Cumulative Effect of Accounting Changes S
2.66 1.40 2.10 2.84 2.69 After Discontinued Operations and Cumulative Effect of Accounting Changes S
2.67 1.39 1.88 2.81 2.69 Dividends Declared per Share of Common Stock*
s 1.9125 1.50 1.50 1.50 1.50 Total Assets
$31,067,944
$32,909,948
$34,386,353
$37,351,513
$17,941,294 Capitalization as of December 31:
Common Stockholders' Equity
$ 8,589,294
$ 8,289,341
$ 7,050,661
$ 7,398,599
$ 4,653,126 Preferred Stock:
Not Subject to Mandatory Redemption 335,123 335,123 335,123 480,194 648,395 Subject to Mandatory Redemption 428,388 594,856 161,105 Long-Term Debt and Other Long-Term Obligations 10,013,349 9,789,066 10,872,216 12.865,352 5,742,048 Total Capitalization S18,937,766
$18,413,530
$18,686,388
$21,339,001
$11,204,674
- Dividends declared in each year include four quarterly dividends of $0.375 per share paid in those years. In addition, a quarterly dividend of S0.4 125 was declared in 2004 payable March 1,2005, increasing the indicated annual dividend rate from $1.50 to $1.65 per share.
PRICE RANGE OF COMMON STOCK The Common Stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE" and is traded on other registered exchanges.
2004 2003 First Quarter High-Low
$39.37 S35.24
$35.19
$27.04 Second Quarter High-Low
$39.73
$36.73
$38.90
$30.57 Third Quarter High-Low
$42.23
$37.04
$38.75
$25.82 Fourth Quarter High-Low
$43.41
$38.35
$35.95
$31.66 Yearly High-Low
$43.41
$35.24
$38.90
$25.82 Prices are based on reports published in The Wall Street Joumal for New York Stock Exchange Composite Transactions.
HOLDERS OF COMMON STOCK There were 143,111 and 142,825 holders of 329,836,276 shares of FirstEnergy's Common Stock as of December 31, 2004 and January 31, 2005, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 10(A) to the consolidated financial statements.
12 FirstEnergy Corp. 2004
Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion includes forward-looking statements based on information currently available to management.
Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms "anticipate, "potential." "expect," "believe,"
estimate" and similar words and include reference to an indicated annual dividend. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements),
adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations, including by the Securities and Exchange Commission, the United States Attorney's Office and the Nuclear Regulatory Commission as disclosed in our Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage in particular, the availability and cost of capital, the continuing availability and operation of generating units, our inability to accomplish or realize anticipated benefits from strategic goals, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investiga-tion into the causes of the August 14, 2003 regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. Dividends declared from time to time during any annual period may in aggregate vary from the indicated amounts due to circumstances considered by the Board at the time of the actual declarations. FirstEnergy expressly disclaims any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.
EXECUTIVE
SUMMARY
On a non-GAAP basis, earnings in 2004 increased to
$991 million, or basic earnings of $3.03 per share of com-mon stock, from earnings of $736 million (basic earnings of $2.42 per share) in 2003 and $889 million (basic earnings of $3.03 per share) in 2002. On a GAAP basis, net income increased to $878 million, or basic earnings of $2.68 per share in 2004 from $423 million (basic earnings of $1.39 per share) in 2003 and $553 million (basic earnings of $1.89 per share) in 2002. The following Non-GAAP Reconciliation displays the unusual items resulting in the difference between GAAP and non-GAAP earnings.
' Non-GAAP Reconciliation 2004 2003 2002 After-tax Basic After-tax Basic Alter-tax Basic Amount Earnings Amount Earnings Amount Earnings.
(Millions) PerShare (Millions) PerShare (Millions) PerShare Earnings Before Unusual items WNon-GAAP)
$991 Cumulative effect of accounting change Discontinued international operations Non-core asset sales/impairments (60)
Davis-Besse impacts (38)
JCP&L disallowance Litigation settlement 111)
Lake plants transaction NRG settlement Long-term derivative contract adjustment Generation project cancellation Other 14)
$3.03 S736
$2.42
$889
$3.03 102 0.33 (101) 10.33)
(80)
(0.27)
(0.19)
(125) 10.411 1621 10.211 10.12)
(170)
(0.56)
(139) 10.47)
(109)
(0.36)
(0.03)
(17)
(0.06) 99 0.33 (11)
(0.04)
(10)
(0.04).
1 0.01)
- 19)
(0.03) 117)
(0.05)
Net Income IGAAP)
$878
$2.68
$423
$1.39
$553
$1.89 I.- -
I I
I
,1.
.. I ---.
The Non-GAAP measure above, earnings before unusual items, is not calculated in accordance with GAAP because it excludes the impact of "unusual items." Unusual items reflect the impact on earnings of events that are not routine, are relat-ed to discontinued businesses or are the cumulative effect of an accounting change. We believe presenting normalized earn-ings calculated in this manner provides useful information to investors in evaluating the ongoing results of our businesses and assists investors in comparing our operating performance to the operating performance of others in the energy sector.
Under our debt paydown and refinancing program, we retired, refinanced, or restructured more than $2.8 billion in long-term debt during the year. These financing activities contributed to the $143 million decrease in interest charges in 2004.
Sales for 2004 were up over the previous year, driven pri-marily by strong sales in the wholesale power market. This increase is largely reflective of a stronger economy and the return of the Davis-Besse Nuclear Power Station to active sta-tus. Despite milder weather experienced over much of our service area in 2004, our generating fleet produced a record 76 billion KWH. Our fossil fleet produced 46 billion KWH and our nuclear fleet produced a record 30 billion KWH.
The Company made a voluntary $500 million contribu-tion to its pension plan in order to help add security to future plan benefits. The net after-tax cost of the contribu-tion was approximately $300 million. This contribution is FirstEnergy Corp. 2004 13
expected to reduce our overall risk profile, because it reduces uncertainty regarding the plan's unfunded liability.
We continue to participate in meaningful settlement negotiations with the parties to the New Source Review case involving our W. H. Sammis Plant (see Environmental Matters). As a result, the U.S. District Court judge hearing the case has delayed without rescheduling the remedy phase of the trial, originally scheduled to begin in January 2005.
In November 2004, the Board of Directors increased our indicated annual dividend to $1.65 per share, payable quarterly at a rate of $0.4125 per share. This action repre-sents a 10% increase over the previous quarterly rate and is the first dividend increase since FirstEnergy was formed in 1997. The Board also adopted a dividend policy that will tar-get sustainable annual dividend increases after 2005 that generally reflect an annual growth rate within the range of 4% to 5%, and an earnings payout ratio generally within the range of 50% to 60%.
At the end of December 2004, accrued dividends of approximately $135 million were included in other current liabilities on the accompanying consolidated balance sheet.
Dividends declared in 2004 were $1.9125 which included quarterly dividends of $0.375 per share paid in each quarter of 2004 and a dividend of $0.4125 payable in the first quar-ter of 2005. The amount and timing of all dividend declarations are subject to the discretion of the Board and its consideration of business conditions, results of opera-tions, financial condition and other factors.
FIRSTENERGY'S BUSINESS FirstEnergy is a registered public utility holding compa-ny headquartered in Akron, Ohio that provides regulated and competitive energy services (see Results of Operations -
Business Segments). Our eight EUOC provide transmission and distribution services and comprise the nation's fifth largest investor-owned electric system - based on serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. ATSI provides transmission services to our Ohio Companies and Penn. The service areas of our EUOC are highlighted below.
Operating Company Area Served Customers Served OE Central and northeastern Ohio 1,031.066 Penn Western Pennsylvania 157,411 CEI Northeastern Ohio 757,889 TE Northwestern Ohio 311,225 JCP&L Northern, western and east central New Jersey 1,061,764 Met-Ed Eastern Pennsylvania 526,380 Penelec Western Pennsylvania 588,066 ATSI Service areas of OE, Penn. CEI and TE Competitive energy services are principally provided by FES. FSG and MYR provide heating, ventilation, air-condi-tioning, refrigeration, process piping, plumbing, electrical and facility control systems and high-efficiency electrotech-nologies. While competitive revenues have increased since 2001, regulated energy services continue to provide the majority of our revenues and earnings.
14 FirstEnergy Cork,. 2004 Beginning in 2001, Ohio utilities that offered both com-petitive and regulated retail electric services were required to implement a corporate separation plan approved by the PUCO - one which provided a clear separation between reg-ulated and competitive operations. FES provides generation services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases and operates fossil and hydroelectric plants owned by the Ohio Companies and Penn. Under the terms of the Ohio Rate Stabilization Plan, the deadline for achiev-ing structural separation by transferring the ownership of applicable EUOC generating assets to a competitive affiliate was extended until twelve months after the termination of the Rate Stabilization Plan, unless otherwise extended fur-ther by the PUCO, or until December 31, 2008, whichever is earlier. All of the power supply requirements for the Ohio Companies and Penn are provided through FES.
FirstEnergy acquired international assets in the merger with GPU in November 2001. GPU Capital and its sub-sidiaries had provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, all of the international operations had been divested because those assets were inconsistent with our vision for FirstEnergy.
STRATEGY We continue to pursue our goal of being the leading regional supplier of energy and related services in the north-east quadrant of the United States, where we see the best opportunities for growth. Our fundamental business strate-gy remains stable and unchanged. While we continue to build a strong regional presence, key elements for our strat-egy are in place and management's focus continues to be on execution. We intend to continue providing competitively priced, high-quality products and value-added services -
energy sales and services, energy delivery, power supply and supplemental services related to our core business.
Our current focus includes: (1) minimizing unplanned extended generation outages; (2) enhancing our system reli-ability; (3) optimizing our generation portfolio; (4) effectively managing commodity supplies and risks; (5) preserving and enhancing appropriate margins; (6) enhancing our credit pro-file and financial flexibility; and (7) managing the skills and diversity of our workforce.
RISKS We face a number of industry and enterprise risks and challenges, including:
- Changes in commodity prices, which could adversely affect our margins;
- Complex and changing government regulations, which could have a negative impact on results of operations;
- Costs of compliance with environmental laws, which are significant, and the cost of compliance with future environmental laws, which could adversely affect cash flow and profitability;
- Financial performance risks related to the economic cycles of the electric utility industry;
- The continuing availability and operation of generating units, which is dependent on retaining the necessary licenses, permits, and operating authority from govern-mental entities, including the NRC;
- Risks of nuclear generation, including uncertainties relating to health and safety, additional capital costs, the adequacy of insurance coverage and nuclear plant decommissioning;
- Operational risks arising from the reliability of our power plants and transmission and distribution equipment;
- Regulatory changes in the electric industry, which could affect our competitive position and result in unrecoverable costs adversely affecting our business and results of operations;
- Human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements;
- Weather conditions such as tornadoes, hurricanes, storms and droughts, as well as seasonal tempera-ture variations;
- A downgrade in credit ratings, which could negatively affect our ability to access capital; and
- We may ultimately incur liability in connection with federal proceedings described in Note 13 to the consolidated financial statements.
RECLASSIFICATIONS As discussed in Notes 1 and 14 to the consolidated financial statements, certain prior year amounts have been reclassified to conform to the current year presentation.
Revenues related to transmission activities previously recorded as wholesale electric sales revenues were reclassi-fied as transmission revenues. Expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and amorti-zation of regulatory assets to conform to the current year presentation of generation commodity costs. As further dis-cussed in Note 14 to the consolidated financial statements, segment reporting in 2003 and 2002 was reclassified to conform to the 2004 business segment organizations and operations. These reclassifications did not change previously reported earnings in 2003 and 2002.
RESULTS OF OPERATIONS The 2004 increase in net income of $455 million from the prior year resulted from several factors. First, the number of unusual charges incurred in 2004 decreased as certain ini-tiatives began to reach their conclusion in 2003 and early 2004. Second, adverse operating results at FSG led to impairment of its goodwill in 2003. Its remaining goodwill and certain other assets were further impaired in 2004 as we prepared to sell the FSG operations. Finally, a positive turn in the economy, moderation in the rate at which alternative suppliers expanded their presence in our franchise areas, and reduced expenses enhanced 2004 financial results.
Moderating those positive results was the absence in 2004 of the NRG settlement gain recorded in 2003 and the cumu-lative effect of an accounting change which offset some of the negative 2003 factors described above.
The $130 million decrease in net income in 2003 com-pared with 2002 reflected many of the factors described above. Additional costs were being incurred during the extended outage at Davis-Besse for replacement power, accelerated maintenance, extended-scope enhancements to plant design and human performance and safety issues.
Also, losses were being recorded on international opera-tions, alternative suppliers were expanding more rapidly in our franchise areas, the economy negatively influenced financial results and we recorded our first impairment of goodwill. In 2003, the NRG settlement gain and cumulative effect of an accounting change offset the negative factors.
The financial results in 2004, 2003 and 2002 are summarized in the table below.
F FirstEnergy 2004 2003 2002 (In millions, except per share amounts) l Total revenues
$12,453
$11,675
$11,453 Income before discontinued operations and cumulative effect of accounting change 874 424 618 Discontinued operations 4
1103)
(65)
Cumulative effect of accounting change 102 Net Income S 878 S 423 S 553 Basic Earnings Per Share:
Income before discontinued operations and cumulative effect of accounting change
$2.67 S1.40
$2.11 Discontinued operations 0.01 (0.34)
(0.22)
Cumulative effect of accounting change 0.33 Net Income
$2.68
$1.39
$1.89 Diluted Earnings Per Share:
Income before discontinued operations and cumulative effect of accounting change
$2.66
$1.40
$2.10 Discontinued operations 0.01 10.34)
(0.22)
Cumulative effect of accounting change 0.33 Net Income
$2.67
$1.39
$1.88 Results of Operations - 2004 Compared With 2003 Sources of changes in total revenues are summarized in the following table:
Increase Sources of Revenue Changes 2004 2003 (Decrease) tIn millions)
Retail Electric Sales:
EUOC - Wires S 4.701 S 4,787
$186)
- Generation 3,158 3,139 19 FES 637 566 71 Wholesale Electric Sales:
EUOC 512 570 158)
FES 1,823 1,143 680 Total Electric Sales 10,831 10,205 626 Transmission Revenues:
EUOC 333 23 310 FES 39 59 120)
Other Revenues:
EUOC 361 443 182)
FES
-Generation 35 10 25 FSG 398 327 71 International 25 (25)
Miscellaneous 456 583 (127)
Total Revenues S12A453
$11.675
$778 Changes in electric generation sales and distribution deliveries in 2004 are summarized in the following table:
FirstEnergy Corp. 2004 15
Changes in KWH Sales Electric Generation Sales:
Retail:
EUOC FES Wholesale Increase (Decrease) 11.5)%
4.9%
26.7%
Total Electric Generation Sales 7.7%
EUOC Distribution Deliveries:
Residential '
2.0%
Commercial' 2.6%
Industrial 0.6%
Total Distribution Deliveries 1.6%
the revenue increase from customers within our franchise areas switching to FES.
The gross generation margin in 2004 improved by $402 million compared to 2003, with electric generation revenue increasing more rapidly than the costs of fuel and purchased power. Excluding the unusual charge resulting from the July 2003 JCP&L rate decision, the gross generation margin improved by $249 million and the ratio of gross generation margin to revenue increased from 26.1 % to 27.1 %, primari-ly reflecting additional lower-cost nuclear generation, offset in part by higher purchased power prices.
Retail sales by our EUOC remain the largest source of revenues, contributing more than 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $67 million decrease in retail electric revenues from our EUOC in 2004.
Sources of the Changes in EUOC Retail Electric Revenue Increase (Decrease)
(In millions)
Changes in Customer Consumption:
Alternative suppliers
$(771 Economy, weather and other 109 32 Changes in Price:
Rate changes, 1191 Shopping incentives 151)
Rate mix and other 1291 199)
Net Decrease S567)
Gross Generation Margin 2004 2003 Increase (In millions)
Electric generation revenue
$6,130 S5.418
$712 Fuel and purchased povver costs 4.469 4.159 310 Gross Generation Margin
$1,661
$1,259
$402 Lower prices were partially offset by increased energy use due to a strengthening economy. Although the demand for energy increased in all three customer groups - residen-tial, commercial and industrial - milder weather in 2004 moderated the energy needs of residential and commercial customers. Customers shopping in our franchise areas for alternative energy suppliers remained a major factor con-tributing to lower EUOC revenues with alternative suppliers providing a larger portion of franchise customer energy requirements.
Alternative suppliers provided 24.3% of the total energy delivered to retail customers in our franchise areas in 2004, compared to 21.8% in 2003. Lower prices resulted from three factors - a shopping credit rate increase, a change in the mix of sales with fewer retail customers receiving EUOC generation in Ohio, and lower base distribution rates at JCP&L. Partially offsetting JCP&Ls lower base distribu-tion rates were higher energy, MTC and SBC rates.
Additional credits provided to customers (primarily under the Ohio transition plan) to promote customer shop-ping for alternative suppliers reduced regulated retail electric sales revenues. Reductions from shopping incentives are deferred for future recovery under our Ohio transition plan and do not affect current period earnings.
Electric sales by FES increased by $751 million primarily from additional sales to the wholesale market that increased
$680 million in 2004. Higher electric sales to the wholesale market were possible due in part to a 13% increase in gen-eration resulting from record production from our generating fleet. Retail sales increased $71 million, with nearly half of Income before discontinued operations and the cumula-tive effect of an accounting change increased $450 million in 2004. In addition to the impact of improved gross genera-tion margin discussed above, the following factors contributed to the change in earnings:
- Lower nuclear expenses of $169 million primarily as a result of one scheduled refueling outage at Beaver Valley Unit 1 in 2004 compared to three scheduled refueling outages in 2003 (Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry) and reduced incre-mental maintenance costs at the Davis-Besse Nuclear Power Station related to its restart;
- Lower energy delivery expenses of $94 million due to reduced storm restoration costs in 2004, a higher level of construction activities in 2004 compared to a higher level of maintenance activities in the prior year and additional distribution reliability expenses incurred in the third quarter of 2003;
- Reduced fossil generation expenses of $49 million due to less maintenance in 2004 compared to the prior year;
- A net $51 million decrease in employee benefits expense primarily as a result of reduced postretire-ment benefit plan expenses (see Postretirement Plans below), offset in part by higher incentive com-pensation and severance costs;
- Lower interest charges of $143 million primarily due to debt and preferred stock redemption and refinancing activities and pollution control note repricings;
- A net $81 million reduction in goodwill impairment charges for FSG with $36 million (see Note 2(H))
and $117 million recognized in 2004 and 2003, respectively; and
- Additional deferrals of regulatory assets of $63 million, due principally to Ohio shopping incentives.
Partially offsetting the above sources of improved earnings were five factors:
- Reduced revenues of $86 million from distribution deliveries due to lower prices;
- Increased amortization of regulatory assets of $87 16 FirstEnergv Corp 2004
million primarily from additional Ohio transition plan amortization and a change in amortization resulting from the July 2003 JCP&L rate decision;
- The absence in 2004 of the 2003 earriings benefit of
$168 million realized from the settlement of our claim against NRG for the terminated sale of four fossil plants;
- An aggregate increase in Ohio property tax expense and other state taxes of $40 million; and
- Increased income taxes of $263 million primarily reflecting higher taxable earnings.
Results of Operations - 2003 Compared With 2002 Sources of changes in total revenues are summarized in the following table:
Increase Sources of Revenue Changes 2003 2002 (Decrease)
(In millions)
Retail Electric Sales:
EUOC - Wires
$4,787
$4,872
$(85)
- Generation 3.139 3,357 (218)
FES 566 348 218 Wholesale Electric Sales:
EUOC 570 511 59 FES 1.143 568 575 Total Electric Sales 10.205 9,656 549 Transmission Revenues:
EUOC 23 39 1161 FES 59 2
57 Other Revenues:
EUOC 443 387 56 FES
- Generation 10 39 (29)
FSG 327 383 156)
International 25 294 (2691 Miscellaneous 583 653 (70)
Total Revenues 511.675
$11453
$ 222 Retail sales by our EUOC contributed more than 70%
of electric revenues and over 60% of total revenues. The following major factors contributed to the $303 million decrease in retail eleciric revenues from our EUOC in 2003:
Sources of the Changes in EUOC Retail Electric Revenue Increase (Decrease)
[in millions)
Changes in Customer Consumption:
Alternative suppliers 5(2951 Economy, weather and other (16) 1311)
Changes in Price:
v Ratechanges 1111 Shopping incentives (6)
Rate mix and other 25 8
jNet Decrease 5(303)
Changes in electric generation sales and distribution deliveries in 2003 are summarized in the following table:
Changes in KWH Sales Increase (Decrease)
Electric Generation Sales:
Retail:
EUOC (7.21%
FES 53.0%
Wholesale 40.2%
Total Electric Generation Sales 8.3; EUOC Distribution Deliveries:
Residential (0.71' Commercial 1.2%
Industrial (0.4)
Total Distribution Deliveries The lower retail electric revenues resulted principally from increased sales by alternative suppliers in our franchise areas. Alternative suppliers provided 21.8% of the total energy delivered to retail customers in our franchise areas in 2003, compared to 15.7% in 2002. As a result, generation kilowatt-hour sales to retail customers of our regulated services were 7.2% lower. Additional credits provided to customers (primarily under the Ohio transition plan) to pro-mote customer shopping for alternative suppliers further reduced regulated retail electric sales revenues. Reductions from shopping incentives are deferred for future recovery under our Ohio transition plan and do not materially affect current period earnings. The NJBPU decision in July 2003 that lowered JCP&L's base electric rates effective August 1, 2003 contributed to lower rates.
Electric sales by FES increased by $793 million primarily from additional sales to the wholesale market that increased
$575 million in 2003 on a 75% increase in kilowatt-hour sales. A majority of the increase was due to sales by our competitive electric energy services segment for a portion of New Jersey's BGS requirements and sales in the spot market. Retail sales by FES increased by $218 million as a result of a 53% increase in kilowatt-hour sales. That increase primarily resulted from retail customers within our Ohio franchise areas switching to FES under Ohio's electricity choice program and from growth in competitive retail sales outside our franchise areas.
The gross generation margin in 2003 declined by $215 million compared to the same period in 2002. Excluding the unusual charge of $153 million of power costs that were disallowed in the July 2003 JCP&L rate decision referred to above, our gross generation margin decreased $62 million and the ratio of gross generation margin to revenue decreased from 30.8% to 26.1 %. Higher electric generation sales resulted principally from the additional sales in the wholesale market and were more than offset by increased fuel and purchased power costs. Purchased power costs increased by $879 million due to higher unit costs and addi-tional quantities purchased. Increased volumes were required to supply obligations assumed by FES for BGS sales in New Jersey, as well as other wholesale commit-ments, and additional supplies were required to replace FirstEnergy Corp. 2004 17
reduced nuclear generation (down 14%). Reduced nuclear generation output resulted from additional refueling outage work performed at the Perry and Beaver Valley plants in 2003 and the Davis-Besse extended outage.
Increase Gross Generation Margin 2003 2002 (Decrease)
(In millions)
Electric generation revenue
$5,41 8
$4,784
$634 Fuel and purchased power costs 4,159 3,310 849 Gross Generation Margin
$1,259
$1.474
$1215)
Income before discontinued operations and the cumula-tive effect of an accounting change decreased $194 million in 2003. In addition to the impact of reduced gross genera-tion margin and lower revenues from distribution deliveries discussed above, the following factors contributed to the decrease in earnings:
- Asset impairment charges of $56 million incurred in 2003 including a $26 million non-cash charge related to the divestiture of our interest in TEBSA; a $13 mil-lion impairment on the monetization of the note received from the sale of our 79.9% interest in Avon; an additional $5 million impairment upon the divesti-ture of our remaining interest in Avon; and $12 million related to the disposition of NEO and the write down of our investment in Pantellos, an internet business-to-business marketplace serving the utility sector;
- A non-cash goodwill impairment charge of $117 mil-lion recorded in the third quarter of 2003 reducing the carrying value of FSG;
- Increased energy delivery costs of $36 million princi-pally due to storm restoration expenses and an accelerated reliability program within JCP&L's service territory;
- Higher nuclear expenses of $54 million as a result of an additional scheduled nuclear refueling outage in 2003 and unplanned work performed during the scheduled refueling outages at the Perry Plant and Beaver Valley Unit 1. The higher production costs were partially offset by lower maintenance costs at the Davis-Besse Nuclear Power Station;
- Planned maintenance outages at three of our fossil generating plants during the fourth quarter of 2003 increased non-nuclear operating expenses by approxi-mately $25 million;
- Increased postretirement plan expenses (see Postretirement Plans below) offset in part by lower incentive compensation costs contributed to a net cost increase of $94 million;
- Revenues less operating expenses for energy-related services declined $17 million due to general declines associated with economic conditions;
- An estimated environmental liability of $15 million was recognized in the fourth quarter of 2003; and
- Increased amortization of regulatory assets of $138 million due principally to additional Ohio transition plan amortization and a July 2003 JCP&L rate case disallowance.
Partially offsetting these higher costs were five factors:
- A settlement of our claim against NRG for the terminated sale of four fossil plants resulted in a $168 million gain;
- Reduced depreciation resulting from several factors lower charges resulting from the implementation of SFAS 143 ($61 million), revised service life assump-tions for nuclear generating plants ($28 million) and reduced depreciation rates resulting from the JCP&L rate case ($18 million);
- Lower interest charges of $146 million primarily due to debt and preferred stock redemption and refinanc-ing activities and pollution control note repricings;
- The absence of unusual charges recognized in 2002 resulted in a further net reduction of other operating expenses ($181 million) in 2003; and
- Reduced income taxes of $106 million primarily reflecting lower taxable earnings.
Cumulative Effect of Accounting Change Results in 2003 included an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003 (see discussion below). We 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 ARO liability at the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, we had recorded decommissioning liabilities of $1.24 billion. We expect substantially all of our nuclear decommis-sioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, we 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 existing decom-missioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, or $102 million net of income taxes. The application of SFAS 143 (excluding the cumulative adjustment described above) resulted in the follow-ing changes to expense categories and net income in 2003:
Effect of SFAS 143 Increase (Decrease)
(In millions)
Other operating expense:
Cost of removal expenditures (previously included in depreciation)
S10 Depreciation:
Elimination of decommissioning expense 189)
Depreciation of asset retirement-cost 2
Accretion of asset retirement liability 42 Elimination of removal cost component (16)
Net decrease to depreciation 161)
Income taxes 21 Net income effect
$30 I8 FirstEnergy Corp. 2004
DISCONTINUED OPERATIONS Discontinued operations for 2004, 2003 and 2002 include FES' natural gas business (see Note 2(J)) which management expects to sell within one year. In 2003 and 2002, discontinued operations were reflected for Emdersa and EGSA, as we substantially completed our exit from for-eign operations acquired through the merger with GPU in 2001. In addition, the results for the FSG subsidiaries, Colonial Mechanical, Webb Technologies and Ancoma, Inc.
and the MARBEL subsidiary, NEO, which were divested in 2003, have been reported as discontinued operations for the years 2003 and 2002. The following table summarizes the sources of income (losses) from discontinued operations:
Discontinued Operations (Net of tax) 2004 2003 2002 (In millions)
Emdersa - abandonment S -
(67)
£ -
EGSA - loss on sale (33)
Ancoma - loss on sale
- 13)
Total losses 1103)
Reclassification of operating income (loss) to discontinued operations:
FES' natural gas business 4
(2) 15 Erndersa, EGSA. Colonial, Webb. Ancoma and NEO -
2 (801 Total
$ 4
$(1031
$(651 POSTRETIREMENT PLANS Strengthened equity markets (reducing pension costs),
as well as amendments to our health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President Bush in December 2003 (reducing OPEB costs) combined to reduce postretirement benefits expenses by
$109 million in 2004 from the prior year. A $191 million increase in benefits expenses in 2003 from 2002 resulted from declines in equity markets in 2001 and 2002 and a reduction in our assumed discount rate in 2002 which increased pension expenses. Also, higher health care pay-ments and a related increase in projected trend rates led to higher OPEB expenses in 2003. The following table reflects the portion of postretirement costs that were charged to expense in 2004, 2003 and 2002.
Postretirement Expenses (Income) 2004 2003 2002 (In millions)
Pension S 83 S 123
$(14)
OPEB 87 156 102 Total
$170
$ 279 5 88 Pension and OPEB expenses are included in various cost categories and have contributed to cost decreases in 2004, discussed above. The $500 million voluntary contribu-tion made in 2004 is expected to result in a reduction in pension costs in 2005, 2006 and 2007 compared to the level they would have been without the voluntary contribu-tion. Including the effect of higher interest costs resulting from funding the voluntary contribution, earnings per share are expected to benefit by approximately $0.06 in each of the next three years. See "Critical Accounting Policies -
Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses.
SUPPLY PLAN Our affiliates are obligated to provide generation service with an estimated power supply of 99.5 billion KWH for 2005. These obligations arise from customers who have elected to continue to receive generation service from our EUOCs under regulated retail rate tariffs and from cus-tomers who have selected FES as their alternate generation provider. Geographically, approximately 63% of the total generation service obligation is for customers located in the MISO market area and 37% for customers located in the PJM market area. Included in the PJM market area are obli-gations of FES to provide power to electric distribution companies in the state of New Jersey, including JCP&L.
FES incurred this obligation as a successful bidder in the State of New Jersey's auction of BGS.
Within the franchise territories of the EUOC, alternative energy suppliers currently provide generation service for approximately 1,800 MW (summer peak) of load with an estimated energy requirement of eight billion KWH. If these alternate suppliers fail to deliver power to their customers located in the EUOC's service areas, the EUOC must pro-cure replacement power in the role of PLR (see Note 2(D) for discussion of the auction of JCP&L's PLR obligation).
JCP&L's costs for any replacement power would be recov-ered under the applicable state regulatory rules.
To meet these generation service obligations, our affili-ates own and operate 13,387 MW of installed generating capacity, which for 2005 is expected to provide approximate-ly 75% of the required power supply. The balance has been secured through a mix of long-term purchases (term of con-tract greater than one year) and short-term purchases (term of contract less than one year). Changes in power supply requirements will be met through spot market transactions.
PJM INTERCONNECTION TRANSACTIONS FES engages in purchase and sale transactions in the PJM Market (see Note 2 (D)) to support the supply of end-use customers, including its BGS obligation in New Jersey and PLR requirements in Pennsylvania. FES meets its supply commitments by transmitting energy into the PJM control area and through bilateral purchased power contracts with counterparties in PJM. FES schedules purchase and sale transactions for each hour in PJM on a day-ahead basis with system balancing occurring real-time. FES sells energy to the PJM Market at the location of its supply (transmitted and con-tracted energy) and purchases energy from the PJM Market at the location of its demand (end-use customer load).
FES accounts for energy transactions in the PJM Market in accordance with EITF 99-19, recognizing purchas-es and sales on a gross basis by recording each discrete transaction (see Note 2(D)). This presentation may not be comparable to other energy companies that have dedicated generating capacity in ISOs or fail to meet the criteria for gross presentation in EITF 99-19.
Firs!Energy Corp. 2004 19
RESULTS OF OPERATIONS - BUSINESS SEGMENTS We have three reportable segments: regulated services, competitive electric energy services and facilities (HVAC) services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment.
"Other" consists of international businesses that have subsequently been divested, MYR (a construction service company); natural gas operations and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable seg-ments." FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey.
The competitive electric energy services business segment primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 2(A) - Accounting for the Effects of Regulation).
The regulated services segment designs, constructs, operates and maintains our regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition costs recovery. The regulated services segment assets include generating units that are leased to the competitive electric energy services.
Its internal revenues represent the rental revenues for the generating unit leases.
The competitive electric energy services segment has responsibility for our generation operations as discussed under Note 2(A) to the consolidated financial statements.
Its net income is primarily derived from revenues from all electric generation sales consisting of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets and the related costs of elec-tricity generation and sourcing of commodity requirements.
Its net income also reflects the expense of the interseg-ment generating unit leases discussed above and property tax amounts related to those generating units.
Segment reporting for 2003 and 2002 was reclassified to conform with the current year business segment organi-zation and operations emphasizing our regulated electric businesses and competitive electric energy operations.
A previous reportable segment was the more expansive competitive services segment whose aggregate operations consisted of our generation operations, natural gas com-modity sales, providing local and long-distance phone service and other competitive energy related businesses such as facilities services and construction service (MYR) which was viewed as offering a comprehensive menu of energy related services. Management's focus is now on our core electric business. This has resulted in a change in per-formance review analysis from an aggregate view of all competitive services operations to a focus on its competi-tive electric energy operations. During our periodic review of reportable segments under SFAS 131, that change resulted in the revision of reportable segments to the separate reporting of competitive electric energy operations, facilities services and including all other competitive services opera-tions in the "Other" segment. Facilities services is being disclosed as a reporting segment due to the subsidiaries qualifying as held for sale (see Note 2 (J)). In addition, cer-tain amounts (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to con-form with the current year presentation of generation commodity costs. Interest expense on holding company debt and corporate support services revenues and expenses are now included in "Reconciling Items" and "Other" includes those operating segment results discussed above.
Financial results discussed below include revenues and expenses from transactions among our business segments.
A reconciliation of segment financial results to consolidated financial results is provided in Note 14 to the consolidated financial statements. Net income (loss) by business seg-ment was as follows:
Net Income (Loss) By Business Segment 2004 2003 2002 (In millions) i Segments::i Regulated services
$1,015 S1,164
$962 I Competitive electric energy services 104 13201 1170) 1 Facilities services 136).
1811 3
Other 45 1160)
(47)
Reconciling Items' 1250)
(180) 1195)
Total S 878 S 423
$553 Includes interest expense on holding company debt corporate support services revenues and expenses ana orner reconcling Irems.
Regulated Services - 2004 versus 2003 Financial results of the regulated services segment were as follows:
Increase Regulated Services
.004 2003 (Decrease) tin millions)
Total revenues S5.713
$5,572
$141 Income before cumulative effect of accounting change 1,015 1,063 148)
Net income 1,015 1,164 1149)
The change in operating revenues resulted from the following sources:
Increase i Sources of Revenue Changes 2004 2003 (Decrease) '
(In millions)
Electric sales 54.701
$4,787 S (86)
Other revenues:
External sales 694 466 228 Internal sales 318 319 (1)
Total Revenues
$5.713 S5,572
$141 The net increase in operating revenues resulted from:
- A decrease of $86 million in retail sales - a $60 mil-lion reduction in revenues from distribution deliveries and a $26 million increase in the credits for shopping incentives to customers; and
- A $228 million increase in other revenues primarily 20 FirstEnergy Corp 2004
due to higher transmission revenues and, to a lesser extent, earnings recognized on decommissioning trust investments (see Note 5 - Investments).
Income before discontinued operations and the cumula-tive effect of an accounting change decreased $48 million.
In addition to the above changes in revenue, the following factors contributed to the change:
- The absence in 2004 of the earnings benefit of the 2003 settlement of our claim against NRG for the ter-minated sale of four fossil plants, which resulted in a
$168 million gain;
- An aggregate increase in Ohio property tax expense and other state taxes of $32 million; and
- Additional MISO and PJM transmission costs of $238 million related to the transmission component of other revenue discussed above.
Partially offsetting those factors were:
- Lower energy delivery expenses (net of refunds to third-party suppliers) of $71 million due to reduced storm restoration costs in 2004, a higher level of con-struction activities in 2004 compared to a higher level of maintenance activities in the prior year and distribution reliability expenses incurred in the third quarter of 2003;
- Lower interest charges of $130 million primarily related to debt and preferred stock redemption and refinancing activities and pollution control note repricings; and
- Reduced income taxes of $38 million primarily reflect-ing reduced taxable earnings.
Regulated Services - 2003 versus 2002 Financial results for regulated services were as follows:
Increase Regulated Services 2003 2002 (Decrease)
(In millions) i Total revenues
$5,572 5,616 S (441
, Income before cumulative effect of accounting change 1,063 962 101 Net income 1,164 962 202 The change in operating revenues resulted from the following sources:
Increase Sources of Revenue Changes 2003 2002 (Decrease)
(in millions)
Electric sales
$4.787
$4,872
$(851 Other revenues:
External sales 466 426 40 Internal sales 319 318 1
Total Revenues
$5,572 S.616
$(44)
The net decrease in operating revenues resulted from:
- A decrease of $85 million in retail sales - a $40 million reduction in revenues from distribution deliveries and a $45 million increase in the credits for shopping incentives to customers; and
- A net $40 million increase in other revenues due in part to JCP&L TBC revenue and jobbing and contract-ing revenue.
Income before discontinued operations and the cumula-tive effect of an accounting change increased $101 million.
The following factors offset the lower revenues and con-tributed to the net increase in income:
- Settlement of our claim against NRG for the terminat-ed sale of four fossil plants which resulted in our recording a $168 million pre-tax credit to earnings;
- Lower interest charges of $95 million primarily related to debt and preferred stock redemption and refinanc-ing activities and pollution control note repricings; and
- The absence of unusual charges recognized in 2002 of $6 million.
Partially offsetting the above sources of improved earnings were four factors:
- Increased energy delivery costs of $41 million princi-pally due to storm restoration expenses and an accelerated reliability program within JCP&L's service territory;
- A net increase in depreciation and amortization expense of $9 million resulting from additional amorti-zation of regulatory assets offset in part by reduced depreciation;
- Additional MISO and PJM transmission costs of $29 million related to the transmission component of other revenue; and
- Increased income taxes of $57 million primarily reflecting higher taxable earnings.
Competitive Electric Energy Services - 2004 versus 2003 Financial results for competitive electric energy services were as follows:
Competitive Electric Energy Services 2004 2003 Increase (In millions)
Total revenues
$6,204
$5,487
$717 Net income (loss) 104 1320) 424 The change in total revenues resulted from the following sources:
Sources of Revenue Changes 2004 2003 Increase (In millions)
Electric sales
$6,130
$5.41B
$712 Other revenues 74 69 5
Total Revenues
$6,204
$5,487
$717 The net increase in electric sales resulted from:
- Higher retail generation sales from customer choice programs ($71 million) and EUOC regulated cus-tomers ($19 million); and
- Increased FES wholesale revenues of $680 million offset in part by a $58 million decrease in sales to EUOC wholesale customers.
The gross generation margin increased $402 million as electric generation revenues increased at a greater rate than the related costs of fuel and purchased power. Higher elec-tric generation revenues resulted from increased sales to both retail and wholesale customers. Excluding the impact Firs tEnergy Corp. 2004 21
of the July 2003 JCP&L rate decision, the gross generation margin increased $249 million, reflecting the benefit of increased sales and the availability of additional lower-cost nuclear generation.
Net income increased $424 million. In addition to the improved gross generation margin discussed above, the fol-lowing factors contributed to the increase in earnings:
- Lower nuclear expenses of $169 million primarily as a result of one scheduled refueling outage at Beaver Valley Unit 1 in 2004 compared to three scheduled refueling outages in 2003 (Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry) and reduced incre-mental maintenance costs at the Davis-Besse Nuclear Power Station related to its restart; and
- Reduced fossil generation expenses of $49 million due to less maintenance in 2004 compared to the prior year.
Partially offsetting the above sources of improved earn-ings were increased income taxes of $294 million reflecting higher taxable earnings.
Competitive Electric Energy Services - 2003 versus 2002 Financial results for competitive electric energy services were as follows:
Competitive Electric Energy Services 2003 2002 Increase (In millions)
Total revenues
$5.487
$4.825 S 662 Netloss 320 170 150 The change in total revenues resulted from the following sources:
Sources of Revenue Changes 2003 2002 Increase (In millions)
Electric sales
$5,418
$4,784
$634 Other revenues 69 41 28
$5,487
$4,825
$662 were partially offset by lower maintenance costs at the Davis-Besse Nuclear Power Station; and
- Planned maintenance outages at three of our fossil generating plants during the fourth quarter of 2003 increased non-nuclear operating expenses by approxi-mately $25 million.
Partially offsetting the above sources of lower earnings were reduced income taxes of $134 million reflecting lower taxable income.
Facilities Services - 2004 versus 2003 Financial results for facilities services were as follows:
Facilities Services 2004 2003 Increase (Decrease)
( (In millions)
Total revenues
$398
$327
$71 Net loss 36 81 (45)
Revenue increased $71 million or 22% in 2004 com-pared to 2003 reflecting stronger market conditions. Losses from FSG goodwill impairment dominated financial results in 2004 and 2003 resulting in non-cash, pre-tax charges to earn-ings of $36 million and $117 million, respectively (see Note 2 (H)). The impairment in 2003 was identified during our annual assessment of goodwill and in 2004 from an analysis per-formed at year-end when a firm decision was made to divest all FSG assets. Excluding the after-tax impact of the goodwill impairments FSG experienced net income in 2004 of $1 mil-lion, following a $255,000 loss in 2003.
Facilities Services - 2003 versus 2002 Financial results for facilities services were as follows:
Facilities Services 2003 2002 (Decrease)
(In millions)
Total revenues
$327
$383
$156)
Net income (loss) 181) 3 184)
The net increase in electric sales resulted from increased FES wholesale revenues of $575 million and increased sales to EUOC wholesale customers of $59 million.
The gross generation margin decreased $215 million as fuel and purchased power costs increased more rapidly than related electric generation revenue. Excluding the unusual charge from the July 2003 JCP&L rate decision, the gross generation margin decreased $62 million, reflecting higher fuel and purchased power costs. Purchased power costs increased due to higher unit costs and additional quantities purchased. Increased volumes were required to supply obli-gations assumed and to replace reduced nuclear generation.
In addition to the reduced gross generation margin dis-cussed above, the following factors contributed to the increase in the net loss:
Higher nuclear expenses of $54 million as a result of an additional scheduled nuclear refueling outage in 2003 and unplanned work performed during the scheduled refueling outages at the Perry Plant and Beaver Valley Unit 1. The higher production costs Revenues decreased $56 million or 15% in 2003 prima-rily reflecting depressed market conditions and reduced customer maintenance services due to mild weather. The loss in 2003 resulted principally from the effect of the $117 million pre-tax charge (discussed above). Excluding the effect of the goodwill impairment, after-tax earnings decreased $3 million in 2003 compared to 2002.
CAPITAL RESOURCES AND LIQUIDITY Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and pre-ferred stock redemptions were met without increasing our net debt and preferred stock outstanding. During 2005, we expect to meet our contractual obligations primarily with cash from operations. Thereafter, we expect 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 22 FirstEnergy Corp. 7004
holding company also has access to $1.375 billion through revolving credit facilities. In 2004, FirstEnergy received $782 million of cash dividends on common stock from its sub-sidiaries and paid $491 million in cash dividends on common stock to its shareholders. There are no material restrictions on the payments of cash dividends by our subsidiaries.
As of December 31, 2004, we had $53 million of cash and cash equivalents, compared with $114 million as of December 31, 2003. Cash and cash equivalents as of December 31, 2003 included $32 million received in December 2003 from the NRG settlement claim sold in January 2004. The major sources for changes in these bal-ances are summarized below.
Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided primarily by our regulated and competitive electric energy businesses (see Results of Operations - Business Segments above). Net cash provided from operating activi-ties was $1.877 billion in 2004, $1.755 billion in 2003 and
$1.932 billion in 2002, summarized as follows:
Operating Cash Flows 2004 2003 2002 Increase (Decrease)
(in millions)
Cash eamings (1
$2,168
$1,825 51.640 Pension trust contributionM 1300)
Working capital and other 9
(70) 292 Total
$1,877
$1,755
$1,932 i (i) Cash earnings are a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $200 million of income tax benefits power contract restructuring transaction, partially offset by a
$237 million decrease in accrued tax balances. Net cash pro-vided from operating activities decreased $177 million in 2003 compared to 2002 due to a $362 million decrease in working capital partially offset by a $185 million increase in cash earnings, as described above under "Results of Operations." The working capital decrease primarily resulted from changes of $388 million in payables and $165 million in prepayments and other current assets, partially offset by a
$196 million increase in accrued tax balances.
Cash Flows From Financing Activities In 2004, 2003 and 2002, net cash used for financing activities of $1.457 billion, $1.298 billion and $1.138 billion, respectively, primarily reflected the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2004, 2003 and 2002:
Securities Issued or Redeemed 2004 2003 2002
{In millions)
New Issues:
- Common stock S
$ 934 S -
Pollution control notes 261 158 Senior secured notes 300 400 370 Unsecured notes 400 627 140
$ 961
$1,961
$ 668 Redemptions:
First mortgage bonds S 589
$1.483
$ 728 Pollution control notes 80 238 93 Senior secured notes 471 323 278 Long-term revolving credit 95 85 Unsecured notes 337 210 Preferred stock 2
127 522
$1,574
$2,256
$1,831 Short-term borrowings, net
$1351) $ 15751 S 479 Cash earnings (in the table above) is not a r performance calculated in accordance with GAP that cash earnings is a useful financial measure provides investors and management with an ad of evaluating our cash-based operating perform~
lowing table reconciles cash earnings with net i neasure of kP. We believe because it riitionnal meansq l
Reconciliation of Cash Earnings 2004 200 (In mi i Net Income (GAAP)
$ 878
$ 4:
Non-Cash Charges (Credits):
Provision for depreciation 590 61 Amortization of regulatory assets 1,166 1.0i Deferralofnewregulatoryassets (257) 111 Nuclear fuel and lease amortization 96 I
Deferred costs recoverable as regulatory assets 1417)
(4; Deferred income taxes' 58 Goodwill impairment 36 1
Disallowed regulatory assets 1!
Cumulative effect of accounting change (1
Other non-cash expenses 18 1:
Cash Earnings (Non-GAAP)
$2,168
$1.8:
3nce. The fol-Net cash used for financing activities increased by $159 ncome.
million in 2004 from 2003. The increase resulted primarily from the absence of a $934 million common equity financ-a 2002 ing in 2003 and a $37 million increase in common stock rllions) dividends partially offset by an $840 million decrease in net 23
$ 553 redemption of preferred securities and debt. Net cash used 07 722 for financing activities in 2003 increased $160 million from 79 941 2002. The increase in cash used for financing activities M4)
(184) resulted primarily from an increase in net redemptions of 56 1
debt and preferred securities of $1.1 billion partially offset
- 27)
(,544) db n
rfre euiiso 11blinprilyofe 54 77 by the common equity financing in 2003.
17 53 We had approximately $170 million of short-term
- 75) indebtedness at the end of 2004 compared to approximately 22 (6)
$522 million at the end of 2003. Available borrowing capabil-25
$1,640 ity as of December 31, 2004 included the following:
ribution in 2004.
Bonrowing Capability FirstEnergy DE Total Excludes $200 million of deferred tax benefit from pension conti Net cash provided from operating activities increased
$122 million in 2004 compared to 2003 due to a $343 mil-lion increase in cash earnings as described under "Results of Operations" and a $79 million increase from changes in working capital, partially offset by a $300 million after-tax voluntary pension trust contribution. The working capital increase resulted in part from changes of $88 million in receivables, $78 million in prepayments and other current assets, $59 million in payables and a $53 million NUG (In millions)
Long-term revolving credit
$1.375
$375
$1,750 Utilized 1215) 1215)
Letters of credit 11351 1135)
Net 1.025 375 1,400 Short-term bank facilities 34 34 Utilized (211 121)
Net 13 13 Total Unused Borrowing Capability
$ 1,025
$388
$1.413 FirstEnergy Corp. 2004 23
At the end of 2004, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures general-ly limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) sup-porting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously out-standing secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not oth-erwise permitted by a specified exception of up to $641 million and $588 million, respectively, as of December 31, 2004. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for sen-ior notes. As of December 31, 2004, JCP&L had the capability to issue $644 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.5 billion of preferred stock (assuming no additional debt was issued) as of the end of 2004. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock (see Note 10(C) - Long-Term Debt and Other Long-Term Obligations for a discussion of debt covenants).
As of December 31, 2004, approximately $1.0 billion remained under FirstEnergy's shelf registration statement, filed with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.
At the end of 2004 and 2003, our common equity as a percentage of capitalization stood at 45% compared to 38%
at the end of 2002. The higher common equity percentage in 2004 and 2003 compared to 2002 reflects net redemptions of preferred stock and long-term debt, and the increase in retained earnings.
Our working capital and short-term borrowing needs are met principally with a syndicated $1 billion three-year revolv-ing credit facility maturing in June 2007. Combined with our syndicated $375 million three-year facility maturing in October 2006, a $125 million three-year facility for OE maturing in October 2006, and a syndicated $250 million two-year facility for OE maturing in May 2005, our primary syndicated credit facilities total $1.75 billion. These revolving credit facilities, combined with an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet our short-term working capital requirements and those of our subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.7 billion as of December 31, 2004.
Borrowings under these facilities are conditioned on maintaining compliance with certain financial covenants in the agreements. FirstEnergy and OE are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually defined fixed charge coverage ratio of no less than 2 to 1. As of December 31, 2004, FirstEnergy's and OE's fixed charge coverage ratios, as defined under the credit agreements, were 4.48 to 1 and 7.15 to 1, respectively. FirstEnergy's and OE's debt to total capitalization ratios, as defined under the credit agreements, were 0.55 to 1 and 0.39 to 1, respectively. FirstEnergy and OE are in compliance with these financial covenants. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in their business, condition (financial or otherwise), results of operations, or prospects.
Neither FirstEnergy's nor OE's primary credit facilities contain any provisions that either restrict their ability to bor-row or accelerate repayment of outstanding advances as a result of any change in their credit ratings. Each primary facility does contain "pricing grids", whereby the cost of funds borrowed under the facility is related to the credit rat-ings of the company borrowing the funds.
Our regulated companies have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but sepa-rate arrangement exists among our unregulated companies.
FESC administers these two money pools and tracks sur-plus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. For the unregulated com-panies, available bank borrowings include only FirstEnergy's
$1.375 billion of revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2004 was 1.43% for the regulated companies' money pool and 1.55% for the unregulated companies' money pool.
Our access to capital markets and costs of financing are influenced by the ratings of our securities. The following table shows our securities ratings as of December 31, 2004.
The ratings outlook from the ratings agencies on all securi-ties is stable.
24 FirstEnergy Corp.,'004
Ratings of Securities Securities S&P Moody's Fitch FirstEnergy Senior unsecured B+
Baa3 BBB-OE Senior secured BBB Baal BBB+
Senior unsecured B+
Baa2 BBB Preferred stock BB Bal BBB-CEI Senior secured BBB-Baa2 BBB-Senior unsecured BB+
Baa3 BB Preferred stock BB Ba2 BB-TE Senior secured BB3-Baa2 BBB-Senior unsecured BB+
Baa3 BB Preferred stock BB Ba2 BB-Penn Senior secured BBB Baal BBB+
Senior unsecured 1X} B+
Baa2 BBB Preferred stock BB Bat BBB-JCP&L Senior secured 8BB+
Baal BBB+
Preferred stock BB Bal BBB Met-Ed Senior secured BBB Baal BBB+
Senior unsecured BBB-Baa2 BBB Penelec Senior secured EBB Baal BBB+
Senior unsecured BBB-Baa2 BBB 1tI Penn s only senior unsecured debt obligations are notes underlying pollution control revenue rehfnding bonds issued by the Ohio Air Quality Development Authority to which bonds this rating applies.
Net cash used for investing activities in 2004 decreased by $88 million from 2003. The decrease was primarily due to $278 million in cash proceeds from certificates of deposit received in the third quarter of 2004 partially offset by a
$117 million change in NUG trust activity. Net cash used for investing activities in 2003 decreased by $264 million from 2002. The decrease was primarily due to a $142 million decrease in property additions and a $174 million increase in cash payments on long-term notes receivable.
Our capital spending for the period 2005-2007 is expected to be about $3.3 billion (excluding nuclear fuel),
of which $979 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $268 million, of which about
$53 million applies to 2005. During the same period, our nuclear fuel investments are expected to be reduced by approximately $280 million and $90 million, respectively, as the nuclear fuel is consumed.
CONTRACTUAL OBLIGATIONS Contractual Obligations As of December 31, 2004, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:
.2006-2W08-Contractual Obligations Total 2005 2007 2009 Thereafter On December 10, 2004, S&P reaffirmed our 'BBB-' corpo-rate credit rating and kept the outlook stable. S&P noted that the stable outlook reflects our improving financial profile and cash flow certainty through 2006. S&P stated that should the two refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the first quarter of 2005 be completed suc-cessfully without any significant negative findings and delays, our outlook would be revised to positive. S&P also stated that a ratings upgrade in the next several months did not seem likely, as remaining issues of concern to S&P, primarily the outcome of environmental litigation and SEC investigations, are not likely to be resolved in the short term.
Cash Flows From Investing Activities Net cash flows used in investing activities resulted principal-ly from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the competitive electric energy services segment are principally generation-relat-ed. The following table summarizes 2004 investments by our regulated services and competitive services segments:
(In millions)
Long-termdebt to
)10.890
$ 710
$1,565 S 622
$ 7,993 Short-term borrowings 170 170 Preferred stock l'1 17 2
14 1
Capital leases m 19 5
6 2
6 Operating leases '2 Z362 183 349 376 1.454 Pension funding 13v Fuel and purchased power 14 13,765 2,464 4,184 3,148 3.969 Total
$27.223
$3.534
$6.118
$4,149 S13.422 Summary of Cash Flows Property Used for Investing Activities Additions Investments Other Total 2004 Sources {Uses) fin millions)
Regulated services S(5721
$181
$ 1881
$(479)
Competitive electric energy services (2461 16
- 12) 1232)
Facilities services 131 2
1)
Other 14?
184
- 16) 174 Reconciling items 121)
(22) 100 57 Total S1846)
$359
$ 6 S1481) 2003 Sources (Uses)
Regulated services
$1434)
$105
$ 16
$(313)
Competitive electric energy services 1335) 132) 8 1359)
Facilities services (4) 61 170) 113)
Other (91) 46 116 153 Reconciling items 174) 28 9
(37)
Total
$1856)
$208
$ 79
$1569) 2002 Sources (Uses)
Regulated services
$1490)
$ 27 S 2
$1461)
Competitive electric energy services 1391) 125) 1416)
Facilities services
- 16)
(6)
Other (9) 96 43 130 Reconciling items (102) 140) 62 1801 Total
$(9981
$83 S 82
$1833)
Vt) Subject to mandatory redemption.
0 See Note 6 to the consolidated financial statements.
1 OWe estimate that no furtherpension contributions wil be required through 2009 to maintain ourdefinedbenefitpensionplans funding ata minimum required level as determined by government regulations. We are unable to estimate projected contributions beyond 2009. See Note 3 to the consolidated financial statements.
IJ4 Amounts under contract with fixed or minimum quantities and approximate timing.
N Amounts reflected do not include interest on long-term debt Guarantees and Other Assurances As part of normal business activities, we enter into various agreements on behalf of our subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratings contingent collateralization provisions.
As of December 31, 2004, our maximum exposure to potential future payments under outstanding guarantees and other assurances totaled approximately $2.4 billion, as summarized below:
FirstEnergy Corp. 2004 25
Guarantees and Other Assurances Maximum Exposure i;: t (In millionsl FirstEnergy Guarantees of Subsidiaries Energy and Energy-Related Contracts (1t S 878 Othert21 2
149 1,027 Surety Bonds 279 LOC
- O3X4, 1,098 Total Guarantees and Other Assurances
$2,404
(') Issued for a one-year term, with a 10-day termination right by FirstEnergy.
a Issued for various terms.
- Includes S135 million issued for various terms under LOC capacity available in FlrstEnergy' revolving credit agreement and $299 million outstanding in support of pollution control revenue bonds issued with various maturities.
(') Includes approximately$216million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and T& $294 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $154 million pledged in connection with the sale and leaseback of Perry Unit I by OE We guarantee energy and energy-related payments of our subsidiaries involved in energy commodity activities -
principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. We also pro-vide guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equip-ment. These agreements legally obligate us to fulfill the obligations of our subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, our guarantee enables the counterparty's legal claim to be satisfied by our other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by us to meet our obli-gations incurred in connection with ongoing energy and energy-related contracts is remote.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obliga-tions, subsequent to the occurrence of a credit rating downgrade or "material adverse event" the immediate post-ing of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of December 31, 2004:
Total Collateral Paid Remaining Collateral Provisions Exposure Cash LOC ExposureMfl agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. We have also provided an LOC (current-ly at $47 million), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
OFF-BALANCE SHEET ARRANGEMENTS We have obligations that are not included on our Consolidated Balance Sheets related to the sale and lease-back arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part of the operating lease payments disclosed above (see Notes 6 and 7). The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of December 31, 2004.
CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided
$84 million of off-balance sheet financing as of December 31, 2004. See Note 12 to the consolidated financial state-ments for additional information regarding this arrangement.
We have equity ownership interests in various busi-nesses that are accounted for using the equity method.
There are no undisclosed material contingencies related to these investments. Certain guarantees that we do not expect to have a material current or future effect on our financial condition, liquidity or results of operations are dis-closed above as contractual obligations.
MARKET RISK INFORMATION We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk manage-ment activities throughout the company. They are responsible for promoting the effective design and imple-mentation of sound risk management programs. They also oversee compliance with corporate risk management poli-cies and established risk management practices.
Commodity Price Risk We are exposed to market risk primarily due to fluctua-tions in electricity, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used prin-cipally for hedging purposes and, to a much lesser extent, for trading purposes. Most of our non-hedge derivative con-tracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2004 is summarized in the following table:
oIn millions) 1 Credit rating downgrade S34
$162
$ 18
$169 Adverse event 135 22 113 Total
$484
$162
$40
$282 01'As of February 7,2005. our total exposure decreased to $476 million and the remaining exposure increased to $290 million - net of $146 million of cash collateral and $40 million of LOC collateral provided to counterparties.
Most of our surety bonds are backed by various indem-nities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to out-side parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
We have 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 26 FIrstEnergy Corp. 2004
Increase 1Decrease) in the Fair Value of Derivative Contracts Non-Hedge Hedge Total (In millions)
Change in the fair value of commodity derivative contracts Outstanding net asset as of January 1, 2004 S 67 S 12
$79 New contract value when entered Additions/change in value of existing contracts
- 14) 6 2
Change in techniques/assumptions Settled contracts
- 11)
(16) 117)
Outstanding net asset as of December 31, 2004 (1" 62 2
64 Non-commodity net assets as of December 31, 2004:
Interest rate swaps ra 4
4 Net Assets - Derivatives Contracts as of December 31, 2004
$ 62
$ 6
$ 68 Impact of Changes in Commodity Derivative Contracts (3)
Income Statement Effects (Pre-Tax)
S 1(5)
$ 15)
Balance Sheet Effects:
DCI (Pre-Tax) 5-
$110)
$110) t1 Includes $61 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability I2) Interest rate swaps are primarily treated as fair value hedges. Changes in derivative values of the fair value hedges are offset by changes in the hedged debts'premium or discount (see Interest Rate Swap Agreements below).
n3)
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 December 31, 2004 as follows:
Non-Hedge Hedge Total (In millions)
Current-Otherassets
$ 2
$ 2
$ 4 Other liabilities
- 12)
- 11) 13)
Non-Current-Other deferred charges 62 15 77 Other noncurrent liabilities (10) 110)
Net assets
$62 S 6
$68 The valuation of derivative contracts is based on observ-able market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an esti-mate of related price volatility. We use these results to develop estimates of fair value for financial reporting purpos-es and for internal management decision making. Sources of information for the valuation of commodity derivative con-tracts by year are summarized in the following table:
Source of Information-Fair Value by Contract Year 2005 2006 2007 2008 Thereafter Total (In millions)
Pricesactivelyquotedll)
$ 2 S 1 5-S-
5-S 3 Other external sources (2) 17 10 27 Prices based on models 10 9
15 34 Total 3
$19
$11
$10 S 9
$15
$64 III Exchange traded.
d7) Broker quote sheets.
Includes $61 million from an embedded option that is offset by a regulatory liability and does not affect eamings.
We perform sensitivity analyses to estimate our expo-sure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2004. We estimate that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would decrease by approximately
$3 million.
Interest Rate Risk Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below.
comparison of Carrying Value to Fair Value There-Fair 1Year of Maturity 2005 2006 2007 2008 2009 after Total Value Assets:
(in millions)
Investments other than Cash and Cash Eluivaents-FiedIrce
$73 S82 S77 $ 57
$68 $1,729 $2,086 $2.243 Average interest rate 6.8% 7.8' 7.9' 737 7.8' 6.0%
6.3' Liabilities:
Long-term Debt and Other Long-term Obligations:
Fixed rate (1)
$495 $1,327 $238 $338 $284 $6,674 $9.356 $9,915 Average interest rate 7.4' 5.7% 6.6% 5.3' 6.8%
6.5x 6.4x Variable rate ti)
$215
$1,319 $1,534 $1,538 I Average interest rate 3.6x 2.2' 2.4 Preferred Stock Subject to Mandatory Redemption
$2 $2 $12 S1
$17
$16 Average dividend rate 7.5% 7.5% 7.6' 7.4 7.6' Short-term Borrowings
$170
$170
$170 Average interest rate 2.4' 2.4' tI Balances and rates do not reflect the fixed-to-floating interestrate swap agreements discussed below We are subject to the inherent interest rate risks relat-ed to refinancing maturing debt by issuing new debt securities. As discussed in Note 6 to the consolidated finan-cial statements, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. While fluctuations in the fair value of our Ohio Companies' decommissioning trust balances will eventually affect earnings (affecting OCI initially) based on the guid-ance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers, or refund to cus-tomers, the difference between the investments held in trust and their decommissioning obligations. Thus, there is not expected to be an earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2004, decommissioning trust balances totaled $1.583 billion, with $975 million held by our Ohio Companies and the bal-ance held by our non-Ohio EUOC. As of year-end 2004, trust balances of our Ohio Companies were comprised of 64%
equity securities and 36% debt instruments.
Interest Rate Swap Agreements We have utilized fixed-to-floating interest rate swap agreements, as part of our ongoing effort to manage the interest rate risk of our 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, fixed interest rates and FirstEnergy Corp. 2004 27
interest payment dates match those of the underlying obli-gations. During the fourth quarter of 2004, in a period of declining interest rates, we unwound swaps with a total notional amount of $400 million. We received $12 million in cash gains from unwinding the swaps and interest expense will be reduced by that amount over the term of the related hedged debt. Due to the differences between fixed and vari-able debt rates, interest expense in 2004 and 2003 was reduced by $37 million and $27 million, respectively. We increased the total notional amount of outstanding interest rate swaps to $1.65 billion as of December 31, 2004, from
$1.15 billion at the end of 2003 from cumulative swap activi-ties. As of December 31, 2004, the debt underlying the interest rate swaps had a weighted average fixed interest rate of 5.53%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.42%.
Fixed to Floating Rate Interest Rate Swaps (Fair value hedges)
December 31, 2004 December 31, 2003 Notional Maturity Fair Notional Maturity Fair Amount Date Value Amount Date Value (Dollars in millions)
$200 2006 SIll
$200 2006 S 1l 100 2008 (11 50 2008 100 2010 1
100 2010 1
100 2011 2
100 2011 1
400 2013 4
350 2013 (1) 100 2014 2
150 2015
- 17) 150 2015 (101.
200 2016 1
150 2018 5
150 2018 l
50 2019 2
50 2019 1
10W 2031 (4) sented 7% of our total credit risk. Within our unregulated energy subsidiaries, 99% of credit exposures, net of collat-eral and reserve, were with investment-grade counterparties as of December 31, 2004.
REGULATORY MATTERS In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regula-tory plans. These provisions include:
- restructuring the electric generation business and allowing the Companies' customers to select a com-petitive electric generation supplier other than the Companies;
- establishing or defining the PLR obligations to cus-tomers in the Companies' service areas;
- providing the Companies with the opportunity to recover 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, trans-mission, distribution and stranded costs recovery charges;
- continuing regulation of the Companies' transmission and distribution systems; and
- requiring corporate separation of regulated and unreg-ulated business activities.
Equity Price Risk Included in nuclear decommissioning trusts are mar-ketable equity securities carried at their current fair value of approximately $951 million and $779 million as of December 31, 2004 and 2003, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in a $95 million reduction in fair value as of December 31, 2004 (see Note 5 - Fair Value of Financial Instruments).
CREDIT RISK Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or other-wise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counter-party performance, whether reflected on or off the balance sheet. We engage in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
We maintain credit policies with respect to our counter-parties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rat-ing for energy contract counterparties of BBB (S&P). As of December 31, 2004, the largest credit concentration was with one party, currently rated investment grade that repre-The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recov-ery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expect-ed to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those opera-tions. Regulatory assets that do not earn a current return totaled approximately $240 million as of December 31, 2004.
l ncrease 4 Regulatory Assets As of December 31 2004 2003 (Decrease)
(In millions)
OE 1.116
$1,451
$ 1335)
CEI 959 1.056 197)
TE 375 459 1841 Penn' 28 1281 JCP&L 2,176 2.558 (382)
Met-Ed 693 1,028 1335)
Penelec 200 497 1297) -
ATSI 13 13 Total
$5,532
$7,077 5(1.545)
Changes in Penn's net regulatory asset components in 2004 resulted in net regulatory liabilities of approximately $18million includedin OtherNoncurrent Liabilities on the Consolidated Balance Sheet as of December 31, 2004.
28 FirstEnergy Corp. 2(104
I Rel I As I -i se Ir Cus I Cus Soc T Los I
Eml 1 Nuc t Ass i Pro P
i0th Toti Regulatory assets by source are as follows:
take, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any lulatory Assets By Source Increase acceptance of future competitive bid results would terminate of December 31 2004..
2003 (Decrease)
(In millions) the Rate Stabilization Plan pricing, but not the related gulatory transition costs
$4.889 56.427 5(1,5381 approved accounting, and not until twelve months after stomer shopping incentives' 612 371 241 i
the PUCO authorizes such termination.
stomer receivables for future income taxes 246 340 (941 ietal benefits charge 51 81 130)
On December 30, 2004, the Ohio Companies filed an s on reacquired debt 89 75 14 application with the PUCO seeking tariff adjustments to plyee postretirement benefits costs 65 77 n12) recover increases of approximately $30 million in transmis-nd spent fuel disposal costs 11691 196)
(73) sion and ancillary service-related costs beginning January 1,
- et removal costs (3401 (3211 (19) 2006. The Ohio Companies also filed an application for perty losses and unrecovered plant costs 50 70 (20) er 39 53 114) authority to defer costs such as those associated with MISO al 55.532 57,077 5(1,545)
Day 1, MISO Day 2, congestion fees, FERC assessment fees, The Ohio Coimpanies are deferring customer shopping incentives and interest costs as newregulatoryassers in accordance with the transition and rate stabilization plans. These regulatory assets. totaling $612 million as of December31. 2004 will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period Ohio On February 24, 2004, the Ohio Companies filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan that the Ohio Companies filed in October 2003. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, the Ohio Companies implemented the accounting modifica-tions related to the extended amortization periods and interest cost deferrals on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing.
The revised Rate Stabilization Plan extends current gen-eration prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:
- extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008;
- deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and
- ability to request increases in generation charges dur-ing 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may cause the Ohio Companies to under-and the ATlI rate increase (described below), as applicable, from October 1, 2003 through December 31, 2005.
See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
New Jersey In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues effective August 1, 2003 and disallowed
$153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceed-ing be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The BPU also ordered that any expenditures and projects under-taken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L's return on equity to 9.75% or decrease it to 9.25%, depend-ing on its assessment of the reliability of JCP&L's service.
Any reduction would be retroactive to August 1, 2003.
JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculat-ing interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances (2) the capital structure includ-ing the rate of return (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning. Management is unable to predict when a decision may be reached by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of FirstEnergy Corp. 2004 29
approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, JCP&L submitted rebuttal testimony on January 4, 2005. Settlement confer-ences are ongoing.
See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
Pennsylvania Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is 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 retains the sup-ply 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 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 a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005 estimated to be approxi-mately $8 million per month.
See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.
Transmission On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC's deci-sion, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmis-sion service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.
On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($13 million deferred as of December 31, 2004 pending authorization) estimated to be incurred from 2004 through 2007. The FERC approved ATSI's request to defer those costs on March 4, 2005.
ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service for-mula rate included in Attachment 0 under the MISO tariff.
The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to elimi-nate the voltage-differentiated rate design for the ATSI zone.
Reliability Initiatives In 2004, we completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training, and emergency response preparedness as recom-mended by various governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. -
Canada Power System Outage Task Force) for completion in 2004. We certified to NERC on June 30, 2004, that we had completed our initiatives with minor exceptions noted, and an independent team led by NERC verified the implementa-tion. Further, we reported to NERC on December 28, 2004 that the minor exceptions were essentially complete.
We are proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the rec-ommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to exist-ing equipment. We note, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhance-ments or may recommend additional enhancements in the future that could require additional, material expenditures.
Finally, the PUCO is continuing to review our filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding. See Note 9 to the consolidated financial statements for a more detailed discussion of reliability initia-tives, including actions by the PPUC that impact Met-Ed, Penelec and Penn.
On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. As a result of an investigation into these outages, the NJBPU issued an order to JCP&L on July 23, 2004 to implement actions to improve reliability in accor-dance with a Special Reliability Master (SRM) report findings and an operations audit.
See Note 9 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.
ENVIRONMENTAL MATTERS We believe we are in compliance with current S02 and NOx reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. Various regulatory and judi-cial actions have since sought to further define NOx 30 FirstEnergy Corp. 2004
reduction requirements (see Note 13(C) - Environmental Matters). We continue to evaluate our compliance plans and other compliance options.
Clean Air Act Compliance The Companies are required to meet federally approved S02 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for S02 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 complying with S02 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electrici-ty from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants.
In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclu-sion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. The Companies believe their facilities are also complying with NOx budgets established under State Implementation Plans (SIP) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
i National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the NAAOS for ozone and proposed a new NAAQS for fine par-ticulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on pro-posed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAOS in other states. The EPA has pro-posed the Interstate Air Quality Rule to "cap-and-trade" NOx and S02 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, S02 emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be sub-stantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.
Mercury Emissions In December 2000, the EPA announced it would pro-ceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern.
On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two dis-tinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of S02 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year.
The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.
W. H. Sammis Plant In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn.
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. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dat-ing back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address any civil penalties and what, if any, actions should be taken to further reduce emis-sions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, 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 consid-er the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact FirstEnergy Corp 2004 31
on FirstEnergy's, OE's and Penn's respective financial condi-tion and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.
Regulation of Hazardous Waste As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from haz-ardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subse-quently determined that regulation of coal ash, as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhaz-ardous waste.
The Companies have been named as PRPs at waste dis-posal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous sub-stances 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 are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2004, 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 SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million as of December 31, 2004. The Companies accrue environmental liabilities only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18% through 2012.
The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on C02 emissions could require significant capi-tal and other expenditures. However, the C02 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-C02 emitting gas-fired and nuclear generators.
Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amend-ments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new per-formance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric gen-erating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake sys-tem and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational meas-ures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance stan-dards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.
OTHER LEGAL PROCEEDINGS Power Outages and Related Litigation Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent cus-tomers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dis-missed for lack of jurisdiction. One case was refiled at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respon-dents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.
One complaint has been filed against FirstEnergy in the New York State Supreme Court. In this case, several plain-tiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No timetable for a deci-sion on the motion to dismiss has been established by the 32 FirstEnergy Corp. 004
Court. No damage estimate has been provided and thus potential liability has not been determined.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
Nuclear Plant Matters In late 2003, FENOC received a subpoena from a grand jury in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. FirstEnergy is unable to predict the outcome of this investigation. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements relating to the Davis-Besse Nuclear Power Station outage made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-
- 01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. FirstEnergy is unable to pre-dict the outcome of this investigation. On February 10, 2005, FENOC received an additional subpoena for documents relat-ed to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002.
On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear i
Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.
Other Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below.
On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve pending lawsuits alleging violations of federal securities laws and related state laws filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and the Ohio Companies of previously reported results, the August 14, 2003 power outages and the extended outage at the Davis-Besse Nuclear Power Station. The settlement agreement, which does not constitute any admission of wrongdoing, provides for a total settlement payment of
$89.9 million. Of that amount, FirstEnergy's in urance carri-ers paid $71.92 million, based on a contractual pre-allocation, and FirstEnergy paid $17.98 million, which resulted in an after-tax charge against FirstEnergy's second quarter earnings of $1 1 million or $0.03 per share of com-mon stock (basic and diluted). On December 30, 2004, the court approved the settlement.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised dur-ing the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notifica-tion, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made sub-ject to liability based on the above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
CRITICAL ACCOUNTING POLICIES We prepare our consolidated financial statements in accordance with GAAR Application of these principles often requires a high degree of judgment, estimates and assump-tions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Our more significant accounting policies are described below.
Regulatory Accounting Our regulated services segment is subject to regulation that sets the prices (rates) we are permitted to charge our customers based on costs that the regule tory agencies deter-mine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be cur-rently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets based on anticipated future cash inflows. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse FirsrEnergy Corp. 2004 33
legislative, judicial or regulatory actions in the future.
Revenue Recognition We follow the accrual method of accounting for rev-enues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts, prices in effect for each customer class and electricity provided by alternative suppliers.
Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations, which impact employee demographics, plan experience and other factors.
Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.
In accordance with SFAS 87, 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 remain-ing 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 signifi-cantly influenced by assumptions about future market conditions and plan participants' experience.
In selecting an assumed discount rate, we consider cur-rently 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 obli-gations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 2004 to 6.00% from 6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.
Our assumed rate of return on pension plan assets con-siders historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2004, 2003 and 2002, plan assets actually earned 11.1 %,
24.2% and (11.3)%, respectively. Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and our pension trust investment allocation of approximately 68%
equities, 29% bonds, 2% real estate and 1 % cash.
In the third quarter of 2004, we made a $500 million voluntary contribution to our pension plan. Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. Our election to pre-fund the plan is expected to eliminate that funding requirement.
As a result of our voluntary contribution and the increased market value of pension plan assets, we reduced our accrued benefit cost as of December 31, 2004 by $424 million. As prescribed by SFAS 87, we reduced our additional minimum liability by $15 million, recording a decrease in an intangible asset of $9 million and crediting OCI by $6 million. The balance in AOCL of $296 million (net of $208 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.
Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2005 composite health care trend rate assumptions are approximately 10%-
12% and 9%-11 %, respectively, gradually decreasing to 5%
in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our pension and OPEB costs and liabilities from changes in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions Assumption Adverse Change Pension.OPEB Total (In millions)
Discount rate Decrease by 0.25*
Slo
$5 S15 Long-term return on assets Decrease by 0.25*
$10 S1 S11 Health care trend rate Increase by 1%
na
$19
$19 Increase in Minimum Liability Discount rate Decrease by 0.25%
$110 na S110 Ohio Transition Cost Amortization In connection with the Ohio Companies' transition plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio Companies. These costs exceeded those deferred or capi-talized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which had 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 transi-tion cost amortization, FirstEnergy includes only the portion 34 FirstEnergy Corp. 2004
of the transition revenues associated with transition costs included on the balance sheet prepared under GAAR Revenues collected for the off-balance sheet costs and the return associated with these costs are recognized as income when received.
Long-LivedAssets In accordance with SFAS 144, we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expect-ed to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, we recog-nize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (dis-counted future net cash flows).
The calculation of future cash flows is based on assumptions, estimates and judgment about future events.
The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.
Nuclear Decommissioning In accordance with SFAS 143, we recognize an ARO for the future decommissioning of our nuclear power plants.
The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measure-ment inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consid-er settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term.
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, we evaluate goodwill for impairment at least annually and make such evaluations more frequently if indicators of impairment arise. In accor-dance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including good-will), the goodwill is tested for impairment. If an impairment is indicated we recognize a loss - calculated as the differ-ence between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2004 with no impairment indicated.
SFAS 142 requires the goodwill of a reporting unit to be tested for impairment if there is a more-likely-than-not expectation that the reporting unit or a significant asset group within the reporting unit will be sold. In December 2004, the FSG subsidiaries qualified as held for sale in accordance with SFAS 144. As required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004.
The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS SFAS 123 (revised 2004) "Share-Based Payment' In December 2004, the FASB issued this revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new stan-dard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain crite-ria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensa-tion. The effective date for FirstEnergy is July 1, 2005 and the Company will be applying modified prospective applica-tion, without restatement of prior interim periods. Any potential cumulative adjustments have not been deter-mined. FirstEnergy uses the Black-Scholes option pricing model to value options and will continue to do so upon adoption of SFAS 123(R). The impacts of the fair value recognition provisions of SFAS 123 on FirstEnergy's net income and earnings per share for 2002 through 2004 are disclosed in Note 4 to the consolidated financial statements.
FirstEnergy is considering alternative compensation strate-gies in conjunction with the adoption of SFAS 123(R).
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments" In March 2004, the EITF reached a consensus on the application guidance for EITF 03-1, which provides a model for determining when investments in certain debt and equi-ty securities are considered other than temporarily impaired.
When an impairment is other-than-temporary, the invest-ment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measure-ment provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.
FirstEnergy Corp. 2004 35
CONSOLIDATED STATEMENTS OF INCOME (In thousands, except per share amounts)
For the Years Ended December 31, 2004 2003 2002 Revenues:
Electric utilities S9,064,853 S8,962,201
$9,165,805 Unregulated businesses 3,388,193 2,712,687 2,287,549 Total revenues 12,453,046 11,674,888 11,453,354 Expenses:
Fuel and purchased power 4,469,484 4,159,143 3,309,658 Other operating expenses 3,558,676 3,796,062 3,927,370 Provision for depreciation 589,652 606,436 721,493 Amortization of regulatory assets 1,166,323 1,079,337 940,991 Deferral of new regulatory assets (256,795)
(194,261)
(183,947)
Goodwill impairment (Note 2(H))
36,471 116,988 General taxes 677.757 637,967 649,400 Total expenses 10,241,568 10,201,672 9,364,965 Claim Settlement (Note 8) 167,937 Income Before Interest and Income Taxes 2,211,478 1,641,153 2,088,389 Net Interest Charges:
Interest expense 670,945 798,911 904,697 Capitalized interest (25,581)
(31,900)
(24,474)
Subsidiaries' preferred stock dividends 21,413 42,369 75,647 Net interest charges 666,777 809,380 955,870 Income Taxes 670,922 407,524 514,134 Income Before Discontinued Operations and Cumulative Effect of Accounting Change 873,779 424,249 618,385 Discontinued operations (net of income taxes (benefit) of $3,038,000,
($3,064,000) and $14,560,000, respectively) (Note 2(J))
4,396 (103,632)
(65,581)
Cumulative effect of accounting change (net of income taxes of $72,516,000) (Note 2(K))
102,147 Net Income S 878,175
$ 422,764
$ 552,804 Basic Earnings Per Share of Common Stock:
Income before discontinued operations and cumulative effect of accounting change 2.67 S
1.40 2.11 Discontinued operations (Note 2(J))
0.01 (0.34)
(0.22)
Cumulative effect of accounting change (Note 2(K) 0.33 Net income 2.68 1.39 1.89 Weighted Average Number of Basic Shares Outstanding 327,387 303,582 293,194 Diluted Earnings Per Share of Common Stock:
Income before discontinued operations and cumulative effect of accounting change 2.66 S
1.40 2.10 Discontinued operations (Note 2(J))
0.01 (0.34)
(0.22)
Cumulative effect of accounting change (Note 2(K) 0.33 Net income 2.67 1.39 1.88 Weighted Average Number of Diluted Shares Outstanding 328,982 304,972 294,421 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
36 FirstEnergy Corp. 2004
CONSOLIDATED BALANCE SHEETS (In thousands)
As of December 31, 2004 2003 ASSETS Current Assets:
Cash and cash equivalents 52Z941 113,975 Receivables-Customers (less accumulated provisions of $34,476,000 and $50,247,000 respectively, for uncollectible accounts) 979,242 1,000,259 Other (less accumulated provisions of $26,070,000 and $18,283,000 respectively, for uncollectible accounts) 377,195 505,241 Materials and supplies, at average cost-Owned 363,547 325,303 Under consignment 94,226 95,719 Prepayments and other 145,196 202,814 2,012,347 2,243,311 Property, Plant and Equipment In service 22,213,218 21,594,746 Less-Accumulated provision for depreciation 9,413,730 9,105,303 12,799,488 12,489,443 Construction work in progress 678,868 779,479 13,478,356 13,268,922 Investments:
Nuclear plant decommissioning trusts 1,582,588 1,351,650 Investments in lease obligation bonds (Note 6) 951,352 989,425 Certificates of deposit (Note 10(C))
277,763 Other 740,026 878,853 3,273,966 3,497,691 Deferred Charges:
Regulatory assets 5.532,087 7,076,923 Goodwill 6,050,277 6,127,883 Other 720,911 695,218 12,303,275 13,900,024
$ 31,067,944 S 32,909,948 LIABILITIES AND CAPITALIZATION Current Liabilities:
Currently payable long-term debt S 940,944 S 1,754,197 Short-term borrowings (Note 12) 170,489 521,540 Accounts payable 610,589 725,239 Accrued taxes 657,219 669,529 Other 929,194 801,662 3,308,435 4,472,167 Capitalization (See Consolidated Statement of Capitalization):
Common stockholders' equity 8,589,294 8,289,341 Preferred stock of consolidated subsidiaries not subject to mandatory redemption 335,123 335,123 Long-term debt and other long-term obligations 10,013,349 9,789,066 18,937,766 18,413,530 Noncurrent Liabilities:
Accumulated deferred income taxes 2,324,097 2,178,075 Asset retirement obligations (Note 11) 1,077,557 1,179,493 Power purchase contract loss liability 2,001,006 2,727,892 Retirement benefits 1,238,973 1,591,006 Lease market valuation liability 936,200 1,021,000 Other 1,243,910 1,326,785 8,821,743 10,024,251 Commitments, Guarantees and Contingencies (Notes 6 and 13)
$ 31,067,944 S 32,909,948 The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
FirstEnergy Corp. 2004 37
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars In thousands, except for share amounts)
As of December 31, 2004 2003 Common Stockholders' Equity:
Common stock, SO.10 par value -authorized 375,000,000 shares-329,836,276 shares outstanding S 32,984
$ 32,984 Other paid-in capital 7,055,676 7,062,825 Accumulated other comprehensive loss (Note 2(l))
(313,112)
(352,649)
Retained earnings (Note 10(A))
1,856,863 1,604,385 Unallocated employee stock ownership plan common stock-2,032,800 and 2,896,951 shares, respectively (Note 4(B))
(43,117)
(58,204)
Total common stockholders' equity 8,589,294 8,289,341 Number of Shares Optional Outstanding Redemption Price 2004 2003 Per Share Aggregate Preferred Stock of Consolidated Subsidiaries Not Subject To Mandatory Redemption (Note 10(B)):
Ohio Edison Company Cumulative, $1 00 par value-Authorized 6,000,000 shares 3.90%
152,510 152,510
$ 103.63
$ 15,804 15,251 15,251 4.40%
176,280 176,280 108.00 19,038 17,628 17,628 4.44%
136,560 136,560 103.50 14,134 13,656 13,656 4.56%
144,300 144,300 103.38 14,917 14,430 14,430 Total 609,650 609,650
$ 63,893 60,965 60,965 Pennsylvania Power Company Cumulative,
$100 par value-Authorized 1,200,000 shares 4.24%
40,000 40,000 103.13 4,125 4,000 4,000 4.25%
41,049 41,049 105.00 4,310 4,105 4,105 4.64%
60,000 60,000 102.98 6,179 6,D00 6,000 7.75%
250,000 250,000 100.00 25,000 25,W0 25,000 Total 391,049 391,049 39,614 39,105 39,105 Cleveland Electric Illuminating Company Cumulative, without par value-Authorized 4,000,000 shares
$ 7.40 Series A 500,000 500,000 101.00 50,500 50,000 50,000 Adjustable Series L 474,000 474,000 100.00 47,400 46,404 46,404 Total 974,000 974,000 97,900 96,404 96,404 Toledo Edison Company Cumulative, $100 par value-Authorized 3,000,000 shares
$4.25 160,000 160,000 104.63 16,740 16,000 16,000
$4.56 50,000 50,000 101.00 5,050 5,000 5,000
$4.25 100,000 100,000 102.00 10,200 10,000 10,000 310,000 310,000 31,990 31,000 31,000 Cumulative, $25 par value-Authorized 12,000,000 shares
$2.365 1,400,000 1,400,000 27.75 38,850 35,000 35,000 Adjustable Series A 1,200,000 1,200,000 25.00 30,000 30,000 30,000 Adjustable Series B 1,200,000 1,200,000 25.00 30,000 30,000 30,000 3,800,000 3,800,000 98,850 95,000 95,000 Total 4,110,000 4.110,000 130,840 126,000 126,000 Jersey Central Power & Light Company Cumulative,
$100 stated value-Authorized 15,600,000 shares 4.00% Series 125,000 125,000 106.50 13.313 1Z649 12,649 38 FirstEnergy Corp. 2004
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)
Long-Term Debt and Other Long-Term Obligations (Note 10(C)) (Interest rates reflect weighted average rates)
(In thousands)
First Mortgage Bonds Secured Notes Unsecured Notes Total As of December31, 2004 2003 2004 2003 2004 2003 2004 2003 Ohio Edison Co.-
Due 2004-2009 6.88% $80,000
$80,000 7.61%
$ 67,476
$ 229,257 4.46% $ 175,000 $ 526,725 Due 2010-2014 7.16%
1,257 1,256 3.70%
50,000 Due 2015-2019 3.80%
156,725 59,000 5.04%
206,000 150,000 Due 2020-2024 7.01%
60,443 60,443 3.87%
50,000 Due 2025-2029 5.75%
119,734 13,522 Due 2030-2034 2.19%
359,800 308,012 3.35%
30,000 Total-Ohio Edison 80,000 80,000 765,435 671,490 511,000 676,725 $1,356,435 $1,428,215 Cleveland Electric Illuminating Co.-
Due 2004-2009 6.86% 125,000 125,000 7.29%
271,700 622,485 27,700 Due 2010-2014 5.72%
378,700 378,700 Due 2015-2019 6.23%
412,630 412,630 Due 2020-2024 5.35%
180,560 186,660 Due 2025-2029 7.59%
148,843 148,843 Due 2030-2034 2.79%
180,995 30,000 7.87%
130,793 103,093 Total-Cleveland Electric 125,000 125,000 1,194,728 1,400,618
=
509,493 509,493 1,829,221 2,035,111 Toledo Edison Co.-
Due 2004-2009 145,000 7.13%
30,000 100,000 85,250 Due 2020-2024 5.37%
166,300 144,500 Due 2025-2029 5.90%
13,851 13,851 Due 2030-2034 2.01%
81.600 51,100 3.90%
90,950 Total-Toledo Edison 145,000 291,751 309,451 90,950 85,250 382,701 539,701 Pennsylvania Power Co.-
Due 2004-2009 9.74%
4,870 40,344 10,300 19,700 Due 2010-2014 9.74%
4,870 4,870 5.40%
1,000 1,000 Due 2015-2019 9.74%
4,903 4,903 4.24%
45,325 45,325 Due 2020-2024 7.63%
6,500 33,750 3.94%
27.182 27,182 Due 2025-2029 4.93%
33,472 23,172 3.38%
14,500 Due 2030-2034 2.04%
5,200 Total-Penn Power 21,143 83,867 112,179 106,979 14,500 19,700 147,822 210,546 Jersey Central Power
& Light Co.-
Due 2004-2009 6.89%
45,985 256,300 5.79%
240,391 255,980 124 Due 2010-2014 5.84%
117,735 117,735 155 Due 2015-2019 7.10%
12,200 12,200 5.46%
522,486 222,486 224 Due 2020-2024 7.50% 125,000 205,000 325 Due 2025-2029 7.18%
200,000 200,000 471 Due 2030-2034 682 Due 2035-2039 987 Total-Jersey Central 383,185 673,500 880,612 596,201 2,968 1,263,797 1,272,669 Metropolitan Edison Co.-
Due 2004-2009 6.61%
37,830 128,265 150,000 5.79%
150,000 248 Due 2010-2014 250,000 4.81%
500,000 310 Due 2015-2019 449 Due 2020-2024 6.10%
28,500 28,500 650 Due 2025-2029 5.95%
13,690 13,690 941 Due 2030-2034 1,364 Due 2035-2039 97,685 Total-Metropolitan Edison 80,020 170,455 400,000 650,000 101,647 730,020 672,102 FirstEnergy Corp. 2004 39
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)
Long-Term Debt and Other Long-Term Obligations (Interest rates reflect weighted average rates)
(In thousands)
First Mortgage Bonds Secured Notes Unsecured Notes Total As of December 31, 2004 2003 2004 2003 2004 2003 2004 2003 Pennsylvania Electric Co.-
Due 2004-2009 6.12%
$ 3,495
$ 3,700 6.23% $ 108,000 $ 233,124 Due 2010-2014 5.35%
24,310 24,310 5.63%
185,000 35,155 Due 2015-2019 6.63%
125,000 125,224 Due 2020-2024 5.80%
20,000 20,000 325 Due 2025-2029 6.05%
25,000 25,000 470 Due 2030-2034 682 Due 2035-2039 96,508 Total-Pennsylvania Electric 72,805 73,010 418,000 491,488
$490,805
$ 564,498 FirstEnergy Corp.
Due 2004-2009 5.98% 1,515,000 1,570,000 Due 2010-2014 6.45% 1,500,000 1,500,000 Due 2030-2034 7.38% 1,500,000 1,500,000 Total-FirstEnergy 4,515,000 4,570,000 4,515,000 4,570,000 Bay Shore Power 6.24%
137,500 140,600 137,500 140,600 Facilities Services Group 5.94%
7,340 7,754 7,340 7,754 FirstEnergy Generation 5.00%
15,000 15,000 15,000 15.000 FirstEnergy Properties 7.89%
9,182 9,438 9,182 9,438 Warrenton River Terminal 6.00%
220 410 220 410 First Communications 6.26%
5,000 5,407 5,000 5,407 Total 762,153 1,350,832 3,398,947 3,642,941 6,728,943 6,477,678 10,890,043 11,471,451 Preferred stock subject to mandatory redemption 16,759 18,514 Capital lease obligations 10,732 13,313 Net unamortized premium on debt 36,759 39,985 Long-term debt due within one year (940,944)
(1,754,197)
Total long-term debt and other long-term obligations 10,013,349 9,789,066 Total Capitalization S18,937,766 $18,413,530 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
40 FirstEnergy Corp. 2004
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Dollars in thousands)
Accumulated Unallocated Other Other ESOP Comprehensive Number Par Paid-In Comprehensive Retained Common Income of Shares Value Capital Income (Loss)
Earnings Stock Balance, January 1. 2002 297,636,276 $29,764 $6,113,260
$(169,003)
$1,521,805
$ (97,227)
Net income
$ 552.804 552,804 Minimum liability for unfunded retirement benefits, net of $(316,681.000) of income taxes (449,615)
(449,615)
Unrealized gain on derivative hedges, net of $37,458,000 of income taxes 59,187 59,187 Unrealized loss on investments, net of 5(3,796,000) of income taxes 15,269)
(5,269)
Currency translation adjustments (91,448)
(91,448)
Comprehensive income
$ 65,659 Stock options exercised (8,169)
Allocation of ESOP shares 15,250 18,950 Cash dividends on common stock 1439.628)
Balance, December 31, 2002 297,636,276 29,764 6,120,341 (656,148) 1,634,981 (78,277)
Net income
$ 422,764 422,764 Minimum liability for unfunded retirement benefits, net of $101,950,000 of income taxes 144,236 144,236 Unrealized loss on derivative hedges, net of $(241,000) of income taxes (347) 1347)
Unrealized gain on investments, net of
$53,431,000 of income taxes 68,162 68,162 Currency translation adjustments 91,448 91,448 Comprehensive income
$ 726,263 Stock options exercised (3,502)
Common stock issued 32,200,000 3,220 930,918 Allocation of ESOP shares 15,068 20,073 Cash dividends on common stock (453,3601 Balance, December 31, 2003 329,836,276 32,984 7,062,825 (352,649) 1,604,385 158,204)
Net income
$ 878,175 878,175 Minimum liability for unfunded retirement benefits, net of $(4,698,000) of income taxes (6,256) 16,256)
Unrealized gain on derivative hedges, net of $9,638,000 of income taxes 19,031 19,031 Unrealized gain on investments, net of
$19,783,000 of income taxes 26,762 26,762 Comprehensive income
$ 917,712 Stock options exercised 124,174)
Allocation of ESOP shares 17,025 15,087 Common stock dividends declared in 2004 payable in 2005 (135,168)
Cash dividends on common stock (490,529)
Balance, December 31, 2004 329,836,276 $32,984 $7,055,676
$ (313,112)
S1,856,863
$ (43,117)
The accompanying Notes to ConsolidatedFinancialStatements are an integralpart of these statements.
FirstEnergy Corp. 2004 41
CONSOLIDATED STATEMENTS OF PREFERRED STOCK (Dollars in thousands)
Not Subject to Mandatory Redemption Subject to Mandatory Redemption Number of Shares Par or Stated Value Number of Shares Par or Stated Value Balance, January 1, 2002 12,449,699
$ 661,044 22,552,751
$ 624,449 Redemptions-7.75% Series (4,000,000)
(100,000)
$7.56 Series B (450,000)
(45,071)
$42.40 Series T (200,000)
(96,850)
$8.32 Series (100,000)
(10,000)
$7.76 Series (150,000)
(15,000)
$7.80 Series (150,000)
(15,000)
$10.00 Series (190,000)
(19,000)
$2.21 Series (1,000,000)
(25,000) 7.625% Series (7,500)
(750)
$7.35 Series C (10,000)
(1,000)
$90.00 Series S (17,750)
(17,010) 8.65% Series J (250,001)
(26,750) 7.52% Series K (265,000)
(28,951) 9.00% Series (4,800,000)
(120,000)
Amortization of fair market value adjustments-
$ 7.35 Series C (9)
$90.00 Series S (258) 8.56% Series (6) 7.35% Series 209 7.34% Series 214 Balance, December 31, 2002 6,209,699 335,123 17,202,500 430,138 Redemptions-7.625% Series (7,500)
(750)
$7.35 Series C (10,000)
(1,000) 8.56% Series (5,000,000)
(125,242)
FIN 46 Deconsolidation-9.00% Series (4,000,000)
(100,000) 7.35% Series (4,000,000)
(92,618) 7.34% Series (4,000,000)
(92,428)
Amortization of fair market value adjustments-
$ 7.35 Series C (7) 8.56% Series (2) 7.35% Series 209 7.34% Series 214 Balance, December 31, 2003 6,209,699
$335,123 185,000 18,514*
Redemptions-7.625% Series (7,500)
(750)
$7.35 Series C (10,000)
(1,000)
Amortization of fair market value adjustments-
$7.35 Series C (5)
Balance, December 31, 2004 6,209,699
$ 335,123 167,500
$ 16,759*
The December 3?. 2003 and 2004 balances for Preferred Stock subject to mandatory redemption are classified as debt under SFAS 150.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
42 FirstEnergy Corp. 2004
CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
For the Years Ended December 31, 2004 2003 2002 Cash Flows From Operating Activities:
Net Income
$ 878,175
$ 422,764
$ 552,804 Adjustments to reconcile net income to net cash from operating activities:
Provision for depreciation 589,652 606,436 721,493 Amortization of regulatory assets 1,166,323 1,079,337 940,991 Deferral of new regulatory assets (256,795)
(194,261)
(183,947)
Nuclear fuel and lease amortization 96,084 66,072 80,507 Other amortization, net (19,436)
(16,278)
(16,593)
Deferred purchased power and other costs (416,617)
(427,092)
(543,644)
Deferred income taxes and investment tax credits, net 258,263 53,639 76,786 Goodwill impairment (Note 2(H))
36,471 116,968 Disallowed regulatory assets 152,500 Investment impairments (Note 2(H))
17,897 43,803 50,000 Cumulative effect of accounting change (174,663)
Deferred rents and lease market valuation liability (84,696)
(119,398)
(84,800)
Revenue credits to customers (71,984)
(43,016)
Accrued retirement benefit obligations 137,742 287,112 124,678 Accrued compensation, net 18,397 (84,503)
(92,197)
Tax refund related to pre-merger period 51,073 Commodity derivative transactions, net (48,840)
(70,498)
(8,682)
Loss (income) from discontinued operations (see Note 2(J))
(4,396) 103,632 65,581 Pension trust contribution (500,000)
Decrease (increase) in operating assets:
Receivables 154,053 66,311 (73,392)
Materials and supplies (36,751) 5,399 (29,134)
Prepayments and other current assets 47,010 (31,155) 133,677 Increase (decrease) in operating liabilities:
Accounts payable (110,947)
(169,652) 218,226 Accrued taxes (15,011) 221,500 25,183 Accrued interest (41,656)
(59,782)
(29,6931 NUG power contract restructuring 52,800 Other (40,872)
(102,445) 47,466 Net cash provided from operating activities 1,876,850 1,754,855 1,932,294 Cash Flows From Financing Activities:
New Financing-Common stock 934,138 Long-term debt 961,474 1,027,312 668,676 Short-term borrowings, net 478,520 Redemptions and Repayments-Preferred stock (1,750)
(127,087)
(522,223)
Long-term debt (1,572,080)
(2,128,567)
(1,308,814)
Short-term borrowings, net (351,051)
(575,391)
Net controlled disbursement activity (2,740) 24,689 (14,083)
Common stock dividend payments (490,529)
(453,360)
(439,628)
Net cash used for financing activities (1,456,676)
(1,298,266)
(1,137,552)
Cash Flows From Investing Activities:
Property additions (846,221)
(856,316)
(997,723)
Proceeds from asset sales 214,258 78,743 155,034 Proceeds from certificates of deposit 277,763 Nonutility generation trusts withdrawals (contributions)
(50,614) 66,327 49,044 Contributions to nuclear decommissioning trusts (101,483) 1101,218)
(103,143)
Avon cash and cash equivalents (Note 8) 31,326 Net assets held for sale (31,326)
Long-term note receivable 82,250 (91,335)
Cash investments (Note 5) 27,082 52,884 81,349 Asset retirements and transfers 9,513 37,580 29,619 Other investments (7,993) 29,137 (7,944)
Other (3,513) 42,067 52,397 Net cash used for investing activities (481,208)
(568,546)
(832,702)
Net decrease in cash and cash equivalents (61,034)
(111,957)
(37,960)
Cash and cash equivalents at beginning of year 113,975 225,932 263,892 Cash and cash equivalents at end of year
$ 52,941
$ 113,975
$ 225.932 Supplemental Cash Flows Information:
Cash Paid During the Year-Interest (net of amounts capitalized)
S 704,067
$ 730,277
$ 881,515 Income taxes S 512,419
$ 161,915
$ 389,180 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FirstEnergy Corp. 2004 43
CONSOLIDATED STATEMENTS OF TAXES (In thousands)
For the Years Ended December 31, 2004 2003 2002 General Taxes:
Kilowatt-hour excise*
$ 236,398
$ 228,216
$ 219,970 State gross receipts 139,616 130,244 132,622 Real and personal property 207,504 183,694 218,683 Social security and unemployment 75,898 68,019 46,345 Other 18,436 28,292 32,709 Total general taxes S 677,852
$ 638,465
$ 650,329 Provision For Income Taxes:
Currently payable-Federal
$ 283,341
$ 306,347
$ 326,417 State 132,356.
118,155 104,867 Foreign (1,165) 20,624 415,697 423,337 451,908 Deferred, net-Federal 245,967 71,910 81,934 State 38,968:
8,133 7,759 Foreign 13,600 284,935 80,043 103,293 Investment tax credit amortization (26,672)
(26,404)
(26,507)
Total provision for income taxes
$ 673,960
$ 476,976
$ 528,694 Reconciliation of Federal Income Tax Expense at Statutory Rate to Total Provision For Income Taxes:
Book income before provision for income taxes
$ 1,552,135
$ 899,740
$ 1,081,498 Federal income tax expense at statutory rate
$ 543,247
$ 314,909
$ 378,524 Increases (reductions) in taxes resulting from-Amortization of investment tax credits (26,672)
(26,404)
(26,507)
State income taxes, net of federal income tax benefit 111,361 82,088 73,207 Amortization of tax regulatory assets 3Z683 31,909 29,296 Preferred stock dividends 7,495 7,202 13,634 Reserve for foreign operations 44,305 48,587 Other, net 5,846 22,967 11,953 Total provision for income taxes S 673,960
$ 476,976
$ 528,694 Accumulated Deferred Income Taxes at December 31:
Property basis differences S 2,451,213
$ 2,293,209 S 2,052,594 Regulatory transition charge 785,312 1,084.871 1,408,232 Customer receivables for future income taxes 103,149 139,335 144,073 Deferred sale and leaseback costs (9Z417)
(95,474)
(99,647)
Nonutility generation costs (174,174)
(221,063)
(228,476)
Unamortized investment tax credits (61,267)
(70,054)
(78,227)
Other comprehensive income (219,020)
(243,743)
(398,883)
Lease market valuation liability (420,078)
(455,074)
(490,698)
Retirement Benefits (185,573)
(359,038)
(223,065)
Oyster Creek securitization (Note 10(C))
184,245 193,558 202,447 Loss carryforwards (463,106).
(495,254)
(507,690)
Loss carryforward valuation reserve 419,978 470,813 482,061 Purchase accounting basis differences (2,657)
(2,657)
(2,657)
Sale of generating assets (9,539)
(11,785)
(11,786)
Provision for rate refund (29,370)
All other 8,031 (49,569)
(149,226)
Net deferred income tax liability
$ 2,324,097
$ 2,178,075
$ 2,069,682
' Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
44 FirstEnergy Corp. 2004
Notes To Consolidated Financial Statements
- 1. Organization and Basis of Presentation FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements also include its other subsidiaries:
FENOC, FES and its subsidiary FGCO, FESC, FirstCom, FSG, GPU Capital, GPU Power and MYR.
FirstEnergy and its subsidiaries follow GAAP and com-ply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, the PUCO, PPUC and NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
FirstEnergy consolidates all majority-owned subsidiaries over which the Company exercises control and, when applica-ble, entities for which the Company has a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis.
Certain prior year amounts have been reclassified to con-form to the current year presentation. Revenue amounts related to transmission activities previously recorded as whole-sale electric sales revenues were reclassified as transmission revenues. Expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and amortization of regulatory assets to con-form to the current year presentation of generation commodity costs. FES' natural gas business has been classified as discon-tinued operations on the Consolidated Statements of Income (See Note 2(J)). As discussed in Note 14, segment reporting in 2003 and 2002 was reclassified to conform to the 2004 busi-ness segment organization and operations.
Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
- 2. Summary of Significant Accounting Policies (A) ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of SFAS 71 to its operating utilities when their rates:
- are established by a third-party regulator with the authority to set rates that bind customers;
- are cost-based; and
- can be charged to and collected from customers.
An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. SFAS 71 is applied only to the parts of the business that meet the above criteria. If a portion of the business applying SFAS 71 no longer meets those requirements, previously recorded regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions, that are reflected in the Companies' respective state regula-tory plans. These provisions include:
- restructuring the electric generation business and allow-ing the Companies' customers to select a competitive electric generation supplier other than the Companies;
- establishing or defining the PLR obligations to customers in the Companies' service areas;
- providing the Companies with the opportunity to recover 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, transmis-sion, distribution and stranded costs recovery charges;
- continuing regulation of the Companies' transmission and distribution systems; and
- requiring corporate separation of regulated and unregulated business activities.
Regulatory Assets The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recov-ery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expect-ed to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those opera-tions. Regulatory assets that do not earn a current return totaled approximately $240 million as of December 31, 2004.
Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
2004 2003 (In millions)
Regulatory transition costs
$4,889
$6,427 Customer shopping incentives 612 371 I Customer receivables for future income taxes 246 340 I Societal benefits charge 51 81 i Loss on reacquired debt 89 75 Employee postretirement benefit costs 65 77 Nuclear decommissioning, decontamination and spentfueldisposalcosts (169) 1961 Asset removal costs (3401 (3211 Property losses and unrecovered plant costs 50 70 Other 39 53 Total
$5,532
$7.077 FirstEnergy Corp. 2004 45
The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans.
These regulatory assets (OE - $228 million, CEI - $295 mil-lion, TE - $89 million, as of December 31, 2004) will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered.
Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized dur-ing that period. OE, TE and CEI expect to recover these deferred customer shopping incentives by August 31, 2008, September 30, 2008 and August 31, 2010, respectively.
Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest method. Under the Rate Stabilization Plan, total transition cost amortization is expected to approximate the following for 2005 through 2009.
TE, respectively) were recognized as regulatory assets recoverable as transition costs through future regulatory cash flows. The following summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, com-pared with the respective company's total assets as of December 31, 2004.
SFAS 71 Discontinued Net Assets Total Assets (In millions)
OE 31,059 55.814 CEI 1,263 6.690 TE 652 2.834 Penn 263 921 JCP&L 39 7.291 Met-Ed 13 3.245 FirstEnergy GE CEI TE (In millions) 2005 5828 3467 3222 3139 2006 404 193 126 85 2007 327 93 139 95 2008 159 159 2009 54 54 The decrease in amortization beginning in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan.
Regulatory transition costs as of December 31, 2004 for JCP&L, Met-Ed and Penelec are approximately $2.2 billion,
$0.7 billion and $0.1 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.2 billion and are being recovered through BGS and MTC revenues. Met-Ed and Penelec have deferred above-market NUG costs totaling approximately $0.5 billion and $0.1 billion, respectively. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costs and a corresponding liability are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue under the provisions of the various regulatory proceedings for New Jersey and Pennsylvania discussed in Note 9.
Accounting for Generation Operations The application of SFAS 71 was discontinued prior to 2001 with respect to the Companies' generation operations.
The SEC's interpretive guidance regarding asset impairment measurement provided that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows.
Consistent with the SEC guidance and EITF 97-4, $1.8 billion of impaired plant investments ($1.2 billion, $227 million, $304 million and $53 million for OE, Penn, CEI and (B) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value.
(C) REVENUES AND RECEIVABLES The Companies' principal business is providing electric service to customers in Ohio, Pennsylvania and New Jersey.
The Companies' retail customers are metered on a cycle basis. Electric revenues are recorded based on energy deliv-ered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading and the end of the month. This estimate includes many factors including estimated weather impacts, customer shopping activity, his-torical line loss factors and prices in effect for each class of customer. In each accounting period, the Companies accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.
Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2004 or 2003, with respect to any par-ticular segment of FirstEnergy's customers. Total customer receivables were $979 million (billed - $672 million and unbilled - $307 million) and $1.0 billion (billed - $664 million and unbilled - $336 million) as of December 31, 2004 and 2003, respectively.
Other receivables include amounts due from customers for unregulated sales and CEl's retained interest in customer receivables sold to CFC (see Note 12).
(D) ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including its BGS obligation in New Jersey and PLR require-ments in Pennsylvania. FES meets its supply commitments by transmitting energy into the PJM control area and through bilateral purchased power contracts with counterparties in PJM. FES schedules purchase and sale transactions for each 46 FirstEnergy Corn 2004
hour in PJM on a day-ahead basis with system balancing occurring real-time. FES sells energy to the PJM Market at the location of its supply (transmitted and contracted energy) and purchases energy from the PJM Market at the location of its demand (end-use customer load).
FES accounts for energy transactions in the PJM Market in accordance with EITF 99-19, recognizing purchases and sales on a gross basis by recording each discrete transaction.
This presentation may not be comparable to other energy companies that have dedicated generating capacity in ISOs or fail to meet the criteria for gross presentation in EITF 99-19.
FES' purchase and sale transactions in the PJM Market for the three years ended December 31, 2004 are summa-rized as follows:
2004 2003 2002 (In millions)
Sales
$1,182 S 665 5 272 Purchases 1,107 B26 376 (E) EARNINGS PER SHARE Basic earnings per share are computed using the weight-ed average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. In 2004, 2003 and 2002, stock-based awards to purchase shares of common stock totaling 0.1 million, 3.3 million and 3.4 million, respectively, were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. The following table recon-ciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations and Cumulative Effect of Accounting Change:
Reconciliation of Basic and Diluted Earnings per Share 2004 2003 2002 (in thousands)
Income Before Discontinued Operations and Cumulative Effect of Accounting Change 5873.779
$424,249
$618,385 Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share (weighted average shares outstanding) 327.387 303,582 293.194 Assumed exercise of dilutive stock options and awards 1.595 1,390 1.227 Denominator for diluted earnings per share 328,982 304,972 294,421 Income Before Discontinued Operations and Cumulative Effect of Accounting Change per common share:
Basic
$2.67
$1.40
$2.11 Diluted
$2.66
$1.40
$2.10 taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service.
The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.
The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for the Companies' electric plant in 2004, 2003 and 2002 are shown in the following table:
Annual Composite Depreciation Rate 2004 2003 2002 OE 2.3%
2.2%
2.4w CEI 2.8 2.8 3.6 TE 2.8 2.8 3.8 Penn 2.2 2.2 2.3 JCP&L 2.1 2.8 3.5 Met-Ed 2.4 2.6 3.0 Penelec 2.5 2.7 3.0 Jointly-Owned Generating Stations JCP&L holds a 50 percent ownership interest in Yards Creek Pumped Storage Facility - its net book value was approximately $19.2 million as of December 31, 2004. All other generating units are owned and/or leased by the Companies individually or together as tenants in common.
Asset Retirement Obligations FirstEnergy recognizes a liability for retirement obliga-tions associated with tangible assets in accordance with SFAS 143. This standard requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capital-ized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 11, "Asset Retirement Obligations".
Nuclear Fuel Property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrich-ment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the units of production method.
(G) STOCK-BASED COMPENSATION FirstEnergy applies the recognition and measurement principles of APB 25 and related Interpretations in account-ing for its stock-based compensation plans (see Note 4).
No material stock-based employee compensation expense is reflected in net income for options as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. FirstEnergy will apply the recognition and measurement principles of SFAS 123R effective July 1, 2005 (see Note 15).
(H) ASSET IMPAIRMENTS Long-Lived Assets FirstEnergy evaluates the carrying value of its long-lived assets when events or circumstances indicate that the car-IF) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value), including payroll and related costs such as FirstEnergy Corp. 2004 47
rying amount may not be recoverable. In accordance with SFAS 144, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposi-tion of the asset. If an impairment exists, a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is estimated by using available market valuations or the long-lived asset's expected future net discounted cash flows. The calculation of expected cash flows is based on estimates and assumptions about future events.
Goodwill In a business combination, the excess of the purchase price over the estimated fair values of 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 makes such evaluations more frequently if indicators of impairment arise.
In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impair-ment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a report-ing unit's goodwill and the carrying value of the goodwill.
FirstEnergy's 2003 annual review resulted in a non-cash goodwill impairment charge of $122 million in the third quar-ter of 2003, reducing the carrying value of FSG. Of this amount, $117 million was reported as an operating expense and $5 million was included in the results from discontinued operations. The impairment charge reflected the slow down in the development of competitive retail markets and depressed economic conditions that affected the value of FSG. The fair value of FSG was estimated using primarily its expected discounted future cash flows.
FirstEnergy's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. In December 2004, the FSG subsidiaries qualified as held for sale in accordance with SFAS 144. SFAS 142 requires the goodwill of a reporting unit to be tested for impairment if there is a more-likely-than-not expectation that the reporting unit or a significant asset group within the reporting unit will be sold. As required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004. FSG's fair value was estimated using current market valuations.
The forecasts used in FirstEnergy's evaluations of good-will reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evalu-ations of goodwill. FirstEnergy's goodwill primarily relates to its regulated services segment. In the year ended December 31, 2004, FirstEnergy adjusted goodwill related to the former GPU companies for interest received on a pre-merger income tax refund and for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were used to offset capital gains generated in 2004. The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described in Note 9. FirstEnergy estimates that completion of transition cost recovery will not result in an impairment of goodwill relating to its regulated business segment.
A summary of the changes in FirstEnergy's goodwill for the years ended December 31, 2004 and 2003 is shown below by segment (See Note 14 - Segment Information):
Competitive Electric Regulated Energy Facilities Services Services Services Other Consolidated; (In millions)
Balance as of Jan. 1. 2003
$5.993 S24
$196
$65
$6,278 Impairment charges (122) 1122)
FSG divestitures 141)
(41)
Other 3
10 13 BalanceasofDec. 31.2003 5.993 24 36 75 6.128 Impairment charges 136) 136)
Adjustments related to GPU acquisition 142)
(42)
Balance as of Dec. 31, 2004 S5.951
$24 S -
$75 S6,050 Investments The Companies periodically evaluate for impairment investments that include available-for-sale securities held by their nuclear decommissioning trusts. In accordance with SFAS 115, securities classified as available-for-sale are eval-uated to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is determined to be other than temporary, the cost basis of the security is written down to fair value. FirstEnergy con-siders, among other factors, the length of time and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The fair value and unrealized gains and losses of the Companies' investments are disclosed in Note 5.
(I) COMPREHENSIVE INCOME Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with common stockholders.
As of December 31, 2004, AOCL consisted of a minimum liability for unfunded retirement benefits of $312 million, unrealized gains on investments in securities available for sale of $91 million, and unrealized losses on derivative instrument hedges of $92 million. As of December 31, 2003, AOCL consisted of a minimum liability for unfunded retirement benefits of $306 million, unrealized gains on investments in securities available for sale of S64 million, and unrealized losses on derivative instrument hedges of
$111 million. Other comprehensive income of $8 million was reclassified to net income in 2004, including an $8 million loss on derivative instrument hedges ($5 million net of tax) and a $22 million gain on available-for-sale securities ($13 million net of tax). Other comprehensive income (loss) reclassified to net income in 2003 and 2002 totaled $29 million and $(10) million, respectively. These amounts were net of income taxes in 2003 and 2002 of
$20 million and $(7) million, respectively.
48 FirstEnergy Corp 2004
J) ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In December 2004, the FSG subsidiaries qualified as held for sale in accordance with SFAS 144. Management anticipates that the transfer of FSG assets,:with a carrying value of $57 million as of December 31, 2004, will qualify for recognition as completed sales within one year. As required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004 (See Note 2(H)). As of December 31, 2004, the FSG subsidiaries classified as held for sale did not meet the criteria for discontinued operations. The carry-ing amounts of FSG's assets and liabilities held for sale are not material to and have not been classified as assets held for sale on FirstEnergy's Consolidated Balance Sheets. See Note 14 for FSG's segment financial information.
FES operates a natural gas business with commercial and industrial customers in Ohio, Pennsylvania and West Virginia.
Sales requirements are sourced through a combination of short-term and long-term supply agreements. In December 2004, FES' natural gas business qualified as held for sale in accordance with SFAS 144. Management expects to complete the sale within one year. As required by SFAS 142, goodwill associated with FES' natural gas business was tested for impairment as of December 31, 2004 with no impairment indi-cated. Financial results are included in discontinued operations on the Consolidated Statements of Income and classified as "Other" in the segment financial information (See Note 14).
FES' natural gas purchases and sales for the three years ended December 31, 2004 are summarized as follows:
2004 2003 2002 (In millions)
Natural gas sales S 496 S 603 S 594 Natural gas purchases 480 583 544 In December 2003, EGSA, GPU Power's Bolivia subsidiary, was sold to Bolivia Integrated Energy Limited.
FirstEnergy included in discontinued operations a $33 million loss on the sale of EGSA in the fourth quarter of 2003 (no income tax benefit was realized) and an operating loss for the year of $2 million. Discontinued operations in 2002 include EGSA's operating income of $10 million.
In April 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandon-ment 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. FirstEnergy included in discontinued operations Emdersa's operating income of $11 million and a $67 million charge for the abandonment in the second quarter of 2003 (no income tax benefit was recognized). An after-tax loss of $87 million (including $109 million in currency transaction losses arising principally from U.S. dollar denomi-nated debt) was included in discontinued operations in 2002.
The FSG subsidiaries, Colonial Mechanical and Webb Technologies, were sold in January 2003 and Ancoma, Inc. was sold in December 2003. The MARBEL subsidiary, NEO was sold in June 2003. The 2003 and 2002 operating results for these divested businesses included in discontinued operations
("Other" in the table below) for the years ended December 2003 and 2002 totaled $(6) million and $5 million, respectively.
Revenues associated with discontinued operations were $496 million, $655 million and $878 million for 2004, 2003 and 2002, respectively. The following table summa-rizes the net income (loss) included in 'Discontinued Operations" on the Consolidated Statements of Income for the three years ended December 31, 2004:
2004 2003 2002 i
(In millions)
FES' natural gas business S 4 S (2)
S 15 EGSA (35) 5 Emdersa (60) 187)
Other (16) 2 Discontinued operations income (loss)
$4
$(103)
$165)
(K) CUMULATIVE EFFECT OF ACCOUNTING CHANGE As a result of adopting SFAS 143 in January 2003, FirstEnergy recorded a $175 million increase to income,
$102 million net of tax, or $0.33 per share of common stock (basic and diluted) in the year ended December 31, 2003. Upon adoption of the accounting standard, FirstEnergy reversed accrued nuclear plant decommissioning costs of $1.24 billion and recorded an ARO of $1.11 billion, including accumulated accretion of $507 million for the peri-od from the date the liability was incurred to the date of adoption. FirstEnergy also recorded asset retirement costs of $602 million as part of the carrying amount of the related long-lived asset and accumulated depreciation of $415 mil-lion. FirstEnergy recognized a regulatory liability of $185 million for the transition amounts subject to refund through rates related to the ARO for nuclear decommissioning. The cumulative effect adjustment also included the reversal of
$60 million of accumulated estimated removal costs for non-regulated generation assets.
IL) INCOME TAXES Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property.
Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are rec-ognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FirstEnergy has capital loss carryforwards of approximately
$1.1 billion, most of which expire in 2007. The deferred tax assets associated with these capital loss carryforwards
($364 million) are fully offset by a valuation allowance as of December 31, 2004, since management is unable to predict FirstEnergy Corp. 2004 49
whether sufficient capital gains will be generated to utilize all of these capital loss carryforwards. Any ultimate utiliza-tion of capital loss carryforwards for which valuation allowances were established through purchase accounting would adjust goodwill.
The Company has also recorded valuation allowances of
$51 million for deferred tax assets associated with impair-ment losses related to certain domestic assets and the divestiture of international assets acquired through the merger with GPU (see Note 8).
FirstEnergy has net operating loss carryforwards for state and local income tax purposes of approximately $884 million. A valuation allowance of $5 million has been record-ed against the associated deferred tax assets of $48 million. These losses expire as follows:
Expiration Period Amount (in millions) 2005-2009 5260 2010-2014 46 2015-2019 217 2020-2023 361
$884
- 3. Pension and Other Postretirement Benefit Plans FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees.
The trusteed plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the project-ed unit credit method. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan. Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. The election to pre-fund the plan is expected to elimi-nate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the voluntary contribution was approximately $300 million.
FirstEnergy provides a minimum amount of noncontrib-utory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their sur-vivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Such factors may be fur-ther affected by business combinations which impact employee demographics, plan experience and other factors.
Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for the majority of its plans.
Obligations and Funded Status As of December 31 Pension Benefits Other Benefits 2004 2003 2004 2003 (In millions)
Change in benefit obligation Benefit obligation as of January 1
$4,162
$3,866 S 2.368
$ 2,077 Service cost 77 66 36 43 Interest cost 252 253 112 136 Plan participants' contributions 14 6
Plan amendments 1281)
(1231 Actuarial Igain) loss 134 222 1211) 323 Benefits paid 1261) 1245) 1108) 194)
Benefit obligation as of December31 $4,364
$4.162 S.1,930 32.368 Change in fair value of plan assets Fair value of plan assets as of January I S3,315
$2,689 S
537 S 473 Actual return on plan assets 415 671 57 88 l Company contribution 500 64 68 Plan participants' contribution 14 2
Benefits paid 1261)
(2451 1108)
(94)
Fair value of plan assets asof December31
$3.969
$3,315 564 S 537 Funded status S1395)
$18471 $ 11.366) 5(1,831)
Unrecognized net actuarial loss 885 919 730 994 Unrecognized prior service cost Ibenefit) 63 72 1378)
(221)
Unrecognized net transition obligation 83 Net asset (liability) recognized
$ 553 S 144 S 11,014)
S (975)
Amounts Recognized in the Consolidated Balance Sheets As of December 31 Accrued benefit cost
$114)
S(438) 5(1.014)
$ (975)
Intangible assets 63 72 Accumulated other comprehensive loss 504 510 Net amount recognized
$553
$ 144
$11,014)
$ (975)
Increase Idecrease) in minimum liability included in other comprehensive income (net of tax)
S 14) $1145)
Assumptions Used to Determine Benefit Obligations As of December31 Discount rate 6.00' 6.25' 6.00' 6.25%
Rate of compensation increase 3.50' 3.50; Allocation of Plan Assets As of December 31 Asset Category Equity securities 68%
70' 74%
71' Debt securities 29 27 25 22 Real estate 2
2 Cash 1
1 1
7 Total 100' 100' 100' 100' Information for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets 2004 2003 (In millionsl Projected benefit obligation
$4,364
$4,162 Accumulated benefit obligation 3.983 3.753 Fair value of plan assets 3,969 3,315 50 FirstEnergy Corp..'004
Components of Net Periodic Benefit Costs Pension Benelits Other Benefits 2004 2003 2002 2004 2003 2002 (In millions)
Servicecost
$77 S 66
$ 59
$ 36
$ 43 S 29 Interest cost 252 253 249 112 137 114 Expected return on plan assets (286) 1248)
(346)
(44)
(43)
(52)
Amortization of prior service cost 9
9 9
(40)
(9) 3 Amortization of transition obligation (asset) 9 9
Recognized net actuarial loss 39 62 39 40 11 Netperiodiccostlincome)
$91
$142 S(29)
$103
$177
$114 Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Pension Benefits Other Benefits 2004 2003 2002 2004 2003 2002 Discount rate 6.25' 6.75' 7.25' 6.25' 6.75' 7.25' Expected long-term return on plan assets 9.00%
9.00' 10.25%
9.00% 9.00% 10.25%
Rate of compensation increase 3.50% 3.50' 4.00%
1-Percentage 1-Percentage Point Increase Point Decrease fIn millions) iEffect on total of service and interest cost
$ 19
$ (16)
Effect on postretirement benefit obligation
$205 S1179)
In selecting an assumed discount rate, FirstEnergy con-siders currently available rates of return on high-quality fixed income investments expected to be available during the peri-od to maturity of the pension and other postretirement benefit obligations. The assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed con-sidering the portfolio's asset allocation strategy.
FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversi-fied across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments.
Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasure-ment of the plan's obligations. The plan amendment, which increases cost sharing by employees and retirees effective January 1, 2005, reduced postretirement benefit costs by
$51 million during 2004.
Consistent with the guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. This reduction was accounted for as an actuarial gain in 2004 pursuant to FSP 106-2. The subsidy reduced net periodic postretirement benefit costs by $48 million during 2004.
As a result of its voluntary contribution and the increased market value of pension plan assets, FirstEnergy reduced its accrued benefit cost as of December 31, 2004 by $424 million. As prescribed by SFAS 87, FirstEnergy reduced its additional minimum liability by $15 million, recording a decrease in an intangible asset of $9 million and crediting OCI by $6 million. The balance in AOCL of $296 million (net of $208 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.
Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:
Pension Benefits Other Benefits P
(In millions) 2005
$ 228 S111 2006 228 106 2007 236 109 2008 247 112 2009 264 115 Years 2010-2014 1.531 627
- 4. Stock-Based Compensation Plans Assumed Health Care Cost Trend Rates As of December 31 2004 2003 Health care cost trend rate assumed for next year (pre/post-Medicare) 9%-11%
10'-12' Rate to which the cost trend rate is assumed to decline Ithe ultimate trend rate) 5%
5%
Year that the rate reaches the ultimate trend rate (pre/post-Medicare) 2009-2011 2009-2011 FirstEnergy has four stock-based compensation pro-grams: Long-term Incentive Program (LTIP); Executive Deferred Compensation Plan (EDCP); Employee Stock Ownership Plan (ESOP); and the Deferred Compensation Plan for Outside Directors (DCPD). FirstEnergy has also assumed responsibility for several stock-based plans through acquisitions. In 2001, FirstEnergy assumed respon-sibility for two stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under GPU's Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock FirstEnergy Corp. 2004 51 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
under both plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. The Centerior Equity Plan (CE Plan) is an additional stock-based plan administered by FirstEnergy for which it assumed responsibility as a result of the acquisition of Centerior Energy Corporation in 1997. All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007.
Stock Option Activities Balance, January 1, 2002 (1,828.341 options exercisablel Options granted Options exercised Options forfeited Balance, December 31, 2002 (1,400,206 options exercisable)
Options granted Options exercised Options forfeited Balance, December 31. 2003 (1.919.662 options exercisable)
Options granted Options exercised Options forfeited Balance, December 31, 2004 (3,175,023 options exercisable)
Number of Options 8,447,688 3,399,579 1,018,852 392.929 10,435,486 3,981,100 455,986 311,731 13,648,869 3.373.459 3,622,148 167,425
.13,232,755 Weighted Average Exercise Price
$26.04 24.83 34.48 23.56 28.19 28.95 26.07 29.71 25.94 29.09 29.27 29.67 38.77 26.52 32.58 32.40 29.07 (A) LTIP FirstEnergy's LTIP includes three stock-based compen-sation programs - restricted stock, stock options, and performance shares.
Under FirstEnergy's LTIP, total awards cannot exceed 22.5 million shares of common stock or their equivalent.
Only stock options and restricted stock have currently been designated to pay out in common stock, with vesting periods ranging from two months to seven years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. As of December 31, 2004, 4.5 million shares were available for future awards.
Restricted Stock Eligible employees receive awards of FirstEnergy com-mon stock subject to restrictions. Those restrictions lapse over a defined period of time or based on performance.
Dividends are received on the restricted stock and are rein-vested in additional shares. Restricted common stock grants under the FE Plan were as follows:
Options outstanding by plan and range of exercise price as of December 31. 2004 were as follows:
Options Options Outstanding Exercisable Weighted Weighted I Avg.
Remaining Avg.
Exercise Contractual
- Exercise, Range of Exercise FE Program Prices Shares Price Life Shares Price FE plan S19.31-$29.87 6,972,940
$28.82 7.0 1,903.790
$26.72 S30.17-$39.46 5,907,710
$36.89
-8.3 919.128
$34.37 Plans acquired Through merger GPU plan
$23.75-S35.92 341,455
$28.35 4.4 341,455
$28.35 MYR plan S 9.35-S14.23 8.550
$12.70 4.5 8.550
$12.70 CE plan
$25.14-S25.15 2,100
$25.14 2.2 2.100
$25.14 Total 13,232.755
$32.40 7.5 3,175,023 $29.07 2004 2003*
2002 Restricted common shares granted 62.370 36,922 Weighted average market price
$40.69
$36.04 Weighted average vesting period (years) 7 3.2 Dividends restricted Yes Yes
' No restricted stock was granted The weighted average fair value of options granted in 2004, 2003 and 2002, respectively, are estimated below using the Black-Scholes option-pricing model and the following assumptions:
204 2003 2002 Fair value per option
$6.72
$5.09
$6.45 Weighted average valuation assumptions:
Expected option term (years) 7.6 7.9 8.1 Expected volatility 26.25w 26.91%
23.31%
Expected dividend yield 3.881 5.09%
4.36%
Risk-free interest rate 1.99%
3.67%
4.60%
Compensation expense for FirstEnergy stock options is based on intrinsic value, which equals any positive differ-ence between FirstEnergy's common stock price on the option's grant date and the option's exercise price. The exer-cise prices of all stock options granted in 2004, 2003 and 2002 equaled the market price of FirstEnergy's common stock on the options' grant dates. If fair value accounting were applied to FirstEnergy's stock options, net income and earnings per share would be reduced as summarized below.
Compensation expense recognized for restricted stock during 2004, 2003 and 2002 totaled $1,982,000, $1,747,000 and $2,259,000, respectively.
Stock Options Stock option grants are provided to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time.
Stock option activities under the FE Programs for the past three years were as follows:
52 FirstEnergy Corp 2004
2004 2003 2002 (In thousands, except per share amounts)
Net Income, as reported
$878.175
$422,764
$552.804 Add back compensation expense reported in net income, net of tax (based on APB 25)'
21,177 23,625 22,981 Deduct compensation expense based upon estimated fair value, net of tax' (35.660)
(35,816)
(31,640)
Proforma net income
$863,692
$410,573
$544,145 Earnings Per Share of Common Stock -
Basic As Reported
$2.68
$1.39
$1.89 Proforma
$2.64
$1.35
$1.86 Diluted As Reported
$2.67
$1.39
$1.88 Proforma
$2.63
$1.35
$1.85
'Includes restricted stock. stock options, performance shares, ESOP EDCP and DCPO.
FirstEnergy anticipates reducing its use of stock options beginning in 2005 and increasing its use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123 may not be representative of its future effect. FirstEnergy has not and does not expect to accelerate out-of-the-money options in anticipation of imple-menting revisions to SFAS 123 on July 1, 2005 (see Note 15
- "New Accounting Standards and Interpretations").
Performance Shares Performance shares are share equivalents and do not have voting rights. The shares track the performance of FirstEnergy's common stock over a three-year vesting peri-od. During that time dividend equivalents are converted into additional shares. The final account value may be adjusted based on the ranking of FirstEnergy stock to a composite of peer companies. Compensation expense recognized for per-formance shares during 2004, 2003 and 2002 totaled
$4,924,000, $7,131,000 and $6,757,000, respectively.
(B) ESOP An ESOP Trust funds most of the matching contribution for FirstEnergy's 401 (k) savings plan. All full-time employees eligible for participation in the 401 (k) savings plan are cov-ered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2004, 2003 and 2002, 864,151 shares, 1,069,318 shares and 1,151,106 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 2,032,800 shares unallocated, as of December 31, 2004, was approximately $80 million. Total ESOP-related compen-sation expense was calculated as follows:
2D04 2003 2D02
/In millions)
Base compensation
$32
$35
$34 Dividends on common stock held by the ESOP and used to service debt (91 (9)
(8)
Net expense
$23
$26
$26 (C) EDCP Under the EDCP, covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy stock account to receive vested stock units. An additional 20 percent premium is received in the form of stock units based on the amount allocated to the FirstEnergy stock account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an elec-tion can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. Of the 1.3 million EDCP stock units author-ized, 776,072 stock units were available for future award as of December 31, 2004. Compensation expense recognized on EDCP stock units in 2004, 2003 and 2002 totaled $2,31 1,000,
$2,312,000 and $206,000, respectively.
{D) DCPD Under the DCPD, directors can elect to allocate all or a portion of their cash retainers, meeting fees and chair fees to a deferred stock or deferred cash accounts. If the funds are deferred into the stock account, a 20 percent match is added to the funds allocated. The 20 percent match and any appreci-ation on it are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, disability, death, upon a change in control, or when a director is ineligible to stand for re-election. Compensation expense is recognized for the 20 percent match over the three-year investing period. Directors may also elect to defer their equity retainers into the deferred stock account, however, they do not receive a 20 percent match for this deferral.
DCPD expenses recognized in 2004, 2003, and 2002 were
$3,556,000, $2,233,000 and $2,728,000, respectively.
- 5. Fair Value of Financial Instruments Long-term Debt and Other Long-term Obligations All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table provides the approximate fair value and related carry-ing amounts of long-term debt and other long-term obligations as of December 31:
2004 Carrying Fair Value Value 2003 Carrying Fair Value Value (In millions)
Long-term debt
$10,787
$11,341
$11,177
$11,648 Subordinated debentures toaffiliatedtrusts 103 112 294 322 Preferred stock subject to mandatory redemption 17 16 19 19
$10,907
$11,469
$11,490
$11,989 The fair values of long-term debt and other long-term FirstEnergy Corp 2004 53
obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by cor-porations with credit ratings similar to the Companies' ratings.
Investments The carrying amounts of cash and cash equivalents approximate fair value due to the short-term nature of these investments. The following table provides the approximate fair value and related carrying amounts of investments other than cash and cash equivalents as of December 31:
losses on nuclear decommissioning trust investments that are deemed to be temporarily impaired as of December 31, 2004:
Less Than 12 Months 12 Months or More Total Fair Unrealized Fair Unrealized Fair Unrealized Value Losses Value Losses Value Losses (In millions)
Debt securities
$175 S 3
$20
$195 S 3 Equity securities 129 12 39 7
168 19
$304
$15 S59
$7
$363
$22 2004 Carrying Fai Value Valt 2003 r
Carrying Fair la Value Value (in millionsl Debt securities: (}
-Government obligations S 797 S 797 S 707 S 707
-Corporate debt securities a 1,205 1,362 1,492 1,601
-Mortgage-backed securities 2
2 2,004 2,161 2,199 2,308 Equity securities (ll 1,033 1,033 1,068 1,068
$3.037
$3,194
$3.267
$3,376 II Includes nuclear decommissioning, nuclear luel disposalandNNUG Mst investments.
0 Includes investments in lease obligation bonds (See Note 6).
The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms.
Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale secu-rities. Decommissioning trust investments are classified as available-for-sale. The Companies have no securities held for trading purposes. The following table summarizes the amor-tized cost basis, unrealized gains and losses and fair values for decommissioning trust investments as of December 31:
2004 2003 Un-Un-Un-i Un-Cost realized rearized Fair Cost realized realized Fair Basis Gains Losses Value Basis Gains Losses Value (In millions)
Debtsecurities S 616 S 19
$ 3 $ 632 S 548 $ 26 S 1 $ 573 Equity securities 763 207 19 951 593 217 31 779
$1,379 $226
$22 31.583 31.141
$243
$32
$1,352 The Companies periodically evaluate the securities held by their nuclear decommissioning trusts for other-than-tem-porary impairment. FirstEnergy considers the length of time and the extent to which the security's fair value has been less than its cost basis and other factors to determine whether impairment is other than temporary. Unrealized gains and losses applicable to the decommissioning trusts of FirstEnergy's Ohio Companies are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually affect earnings. The decommissioning trusts of FirstEnergy's Pennsylvania and New Jersey Companies are subject to regulatory accounting in accordance with SFAS
- 71. Net unrealized gains and losses are recorded as regula-tory liabilities or assets since the difference between investments held in trust and the decommissioning liabilities are recovered from, or refunded to, customers.
The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securi-ties of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.
Derivatives FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for 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 members of senior management, provides general management oversight to risk management activities throughout the Company.
They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
How derivative instruments are used and classified deter-mines how they are reported in FirstEnergy's financial statements. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. The changes in the fair value of a derivative instrument are recorded in current earnings, in other comprehensive income, or as part of the value of the hedged item depending on whether or not it is designated as part of a hedge transaction and on the nature of the hedge transaction. FirstEnergy's primary ongoing hedging Proceeds from the sale of decommissioning trust investments, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2004 were as follows:
2004 2003 2002 (In millions)
Proceeds from sales
$1,234 S 758
$599 Realized gains 144 38 32 Realized losses 43 32 47 Interest and dividend income 45 37 33 The following table provides the fair value of and unrealized 54 FirstEnergy Corp. 2904
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 com-modity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. The impact of ineffectiveness on earnings during 2004 was not material. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a por-tion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt are 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. AOCL as of December 31, 2004 includes a net deferred loss of $92 million for derivative hedging activity. The $19 million decrease from the December 31, 2003 balance of $111 million includes an $11 million reduction due to the sale of GLEP, a $3 million reduction related to current hedging activity and a $5 million decrease due to net hedge losses included in earnings during the year. Approximately $14 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.
The fair value of these derivative instruments will continue to fluctuate from period to period based on various market factors.
During 2004, FirstEnergy executed fixed-for-floating interest rate swap agreements, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities and pays variable cash flows based on short-term variable market inter-est rates (3 and 6 months LIBOR index). 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 received, and interest payment dates match those of the underlying obligations. FirstEnergy entered into inter-est rate swap agreements on a $900 million notional amount of subsidiaries' senior notes and subordinated debentures with a weighted average fixed interest rate of 5.67%. In addition, FirstEnergy unwound swaps with a total notional amount of $400 million from which it received $12 million in cash gains during 2004. The gains will be recognized over the remaining maturity of each respective hedged security as reduced interest expense. As of December 31, 2004, the aggregate notional value of interest rate swap agreements outstanding was $1.65 billion.
FirstEnergy engages in the trading of commodity deriva-tives and periodically experiences net open positions.
FirstEnergy's risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. Discretionary trad-ing in 2004 resulted in a $2 million gain.
- 6. Leases The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.
OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership inter-ests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respec-tive leases, OE, CEI and TE continue to be responsible, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including con-struction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning.
They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair mar-ket value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.
Consistent with the regulatory treatment, the rentals for capi-tal and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2004 are summarized as follows:
2004 2003 2002
[In millions)
Operating leases Interest element
$172
$181
$188 Other 126 150 136 Capital leases Interest element 1
2 2
Other 3
2 3
Total rentals
$302
$335
$329
-.......~.......
OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to pur-chase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport Capital Trust arrangements effectively reduce lease costs related to those transactions (see Note 7).
The future minimum lease payments as of December 31, 2004 are:
DOperating Leases Capital Lease Capital Leases Payments Trusts Net (In millions) 2005
$5
$ 313
$ 130
$ 183 2006 5
322 142 180 2007 1
299 130 169 2008 1
294 105 189 2009 1
298 111 187 Years thereafter 6
2.217 763 1,454 Total minimum lease payments 19
- $3,743
$1.381
$2,362 Executory costs 4
Net minimum lease payments 15 Interest portion 4
Present value of net minimum lease payments 11 Less current portion 2
Noncurrent portion S 9 FirstEnergy Corp. 2004 55
FirstEnergy has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant asso-ciated with the 1997 merger between OE and Centerior.
The total above-market lease obligation of $722 million asso-ciated with Beaver Valley Unit 2 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $37 million per year). The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $48 million per year). As of December 31, 2004 the above-market lease lia-bilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled S1.0 billion, of which $85 million is current.
- 7. Variable Interest Entities FIN 46R, addresses the consolidation of VIEs, including spe-cial-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the residual economic risks and rewards. FirstEnergy adopted FIN 46R for special-purpose entities as of December 31, 2003 and for all other entities in the first quarter of 2004. The first step under FIN 46R is to determine whether an entity is within the scope of FIN 46R, which occurs if it is deemed to be a VIE. FirstEnergy and its subsidiaries consolidate VIEs where they have determined that they are the primary beneficiaries as defined by FIN 46R.
Leases Included in FirstEnergy's consolidated financial state-ments are PNBV and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with the sale and leaseback transac-tions discussed above in Note 6. PNBV and Shippingport financial data are included in the consolidated financial state-ments of OE and CEI, respectively.
PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a whol-ly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connec-tion with CEl's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
Through its investment in PNBV, OE has, and through their investments in Shippingport, CEI and TE have, variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were therefore not required to consolidate these entities. The combined purchase price of $3.1 billion for all of the inter-ests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million.
CE, CEI and TE are exposed to losses under the appli-cable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the appli-cable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $673 million,
$115 million and $570 million, respectively, that would not be payable if the casualty value payments are made.
Power Purchase Agreements FirstEnergy has evaluated its power purchase agree-ments and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant's variable costs of produc-tion. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power pur-chase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but nine of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R.
JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.
As required by FIN 46R, FirstEnergy requests, on a quarterly basis, the information necessary from these nine entities to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary.
FirstEnergy has been unable to obtain the requested infor-mation, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. The cost of power purchased from these entities during 2004, 2003 and 2002 was $210 mil-lion, $194 million and $184 million, respectively.
FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consoli-dating any such entity without this information.
- 8. Divestitures International Operations FirstEnergy completed the sale of its international oper-ations in January 2004 with the sales of its remaining 20.1 56 FirstEnergy Corp. 2)04
percent interest in Avon (parent of Midlands Electricity in the United Kingdom) on January 16, 2004, and its 28.67 percent interest in TEBSA for $12 million on January 30, 2004. Impairment charges related to TEBSA and Avon (included in Other Operating Expenses on the Consolidated Statements of Income) were recorded in the fourth quarter of 2003 and no gain or loss was recognized upon the sales in 2004. Avon, TEBSA and other international assets sold in 2003 were originally acquired as part of FirstEnergy's November 2001 merger with GPU.
International operations in Bolivia were divested by the December 2003 sale of FirstEnergy's wholly owned sub-sidiary, Guaracachi America, Inc., a holding company with a 50.001 percent interest in EGSA, resulting in a loss on sale of S33 million (recognized in Discontinued Operations in the Consolidated Statement of Income for the year ended December 31, 2003). International operations in Argentina represented by FirstEnergy's ownership in Emdersa were divested through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. in April 2003. As a result of the abandonment, FirstEnergy rec-ognized a one-time, non-cash charge of $67 million, or $0.23 per share of common stock in the second quarter of 2003.
The charge did not include the expected income tax bene-fits related to the abandonment, which were fully reserved during the second quarter of 2003. FirstEnergy expects 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.
FirstEnergy had sold a 79.9 percent equity interest in Avon in May 2002 to Aquila, Inc. for approximately $1.9 bil-lion (consisting of the assumption of $1.7 billion of debt,
$155 million in cash and a $87 million note receivable). In the fourth quarter of 2002, FirstEnergy recorded a $50 mil-lion after-tax charge to reduce the carrying value of its remaining 20.1 percent interest. After reaching agreement to sell its remaining 20.1 percent interest in the fourth quar-ter of 2003, FirstEnergy recorded a $5 million after-tax charge to reduce the carrying value. These charges were included in Other Operating Expenses on the Consolidated Statements of Income for the years ended December 31, 2002 and 2003, respectively. In the second quarter of 2003, FirstEnergy recognized an impairment of $13 million ($8 mil-lion net of tax) related to the carrying value of the note receivable from Aquila. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of its note receivable in the secondary market and received $63 million in pro-ceeds in July 2003.
Generation Assets In August 2002, FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not complete the transaction under the original terms of the agreement. NRG filed voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an agreement for settlement of its claim against NRG. FirstEnergy sold its entire claim (including $32 million of cash proceeds received in December 2003) for $170 million in January 2004.
Other Domestic Operations FirstEnergy sold its 50 percent interest in GLEP on June 23, 2004. Proceeds of $220 million included cash of
$200 million and the right, valued at $20 million, to partici-pate for up to a 40% interest in future wells in Ohio. This transaction produced an after-tax loss of $7 million, or $0.02 per share of common stock, including the benefits of prior tax capital losses that had been previously fully reserved, which offset the capital gain from the sale. In 2003, FirstEnergy sold three FSG subsidiaries - Ancoma, Inc., a mechanical contracting company based in Rochester, New York, and Virginia-based Colonial Mechanical and Webb Technologies - and a MARBEL subsidiary - Northeast Ohio Natural Gas (see Note 2(J)).
- 9. Regulatory Matters Reliability Initiatives In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability enti-ties (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. With respect to each of these reliability enhancement initiatives, FirstEnergy submitted its response to the respective entity according to any required response dates. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readi-ness and training, and emergency response preparedness recommended for completion in 2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with minor exceptions noted, that FirstEnergy had completed the rec-ommended enhancements, policies, procedures and actions it had recommended be completed by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a tech-nical assistance team of experts to assist in implementing and confirming timely and successful completion of various initiatives. The NERC-assembled independent verification team confirmed on July 14, 2004, that FirstEnergy had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor exceptions noted by FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its June 30, 2004 Certification and Report of Completion to NERC addressing the minor exceptions, which are now essentially complete.
FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subse-FirstEnergv Corp 2004 57
quent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for fore-casted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhance-ments in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.
On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. On July 16, 2003, the NJBPU ini-tiated an investigation into the cause of JCP&L's outages of the July 4, 2003 weekend. The NJBPU selected an SRM to oversee and make recommendations on appropriate cours-es of action necessary to ensure system-wide reliability.
Additionally, pursuant to the stipulation of settlement that was adopted in the NJBPU's Order of March 13, 2003 in its docket relating to the investigation of outages in August 2002, the NJBPU, through an independent auditor working under direction of the NJBPU Staff, undertook a review and focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit).
Subsequent to the initial engagement of the auditor, the scope of the review was expanded to include the outages during July 2003.
Both the independent auditor and the SRM submitted interim reports primarily addressing improvements to be made prior to the next occurrence of peak loads in the sum-mer of 2004. On December 17, 2003, the NJBPU adopted the SRM's interim recommendations related to service relia-bility. With the assistance of the independent auditor and the SRM, JCP&L and the NJBPU staff created a Memorandum of Understanding (MOU) that set out specific tasks to be performed by JCP&L and a timetable for completion. On March 29, 2004, the NJBPU adopted the MOU and endorsed JCP&L's ongoing actions to implement the MOU.
On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of the SRM and the Executive Summary and Recommendation portions of the final report of the Focused Audit. A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. JCP&L continues to file compliance reports reflecting activities asso-ciated with the MOU and Stipulation.
In May 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage manage-ment systems following restructuring. Evidentiary hearings have been scheduled for September 2005. FirstEnergy is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal inves-tigation of whether Met-Ed's, Penelec's and Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Hearings were held in early August 2004.
On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settle-ment, Met-Ed, Penelec and Penn agreed to enhance service reliability, ongoing periodic performance reporting and com-munications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expen-ditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hear-ing process if remediation is unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
Ohio In October 2003, the Ohio Companies filed an applica-tion for a Rate Stabilization Plan with the PUCO to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncer-tainty following the end of the Ohio Companies' transition plan market development period. On February 24, 2004, the Ohio Companies filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications related to the extended amortization periods and interest costs deferral on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing.
The revised Rate Stabilization Plan extends current gen-eration prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:
- extension of the transition cost amortization period for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008;
- deferral of interest costs on the accumulated cus-tomer shopping incentives as new regulatory assets; and 58 FirstEnergy Corp. ;'004
- ability to request increases in generation charges dur-ing 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may cause the Ohio Companies to under-take, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008.
Any acceptance of future competitive bid results would ter-minate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.
New Jersey 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 NUG agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2004, the accumulated deferred cost balance totaled approximately $446 million.
New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determi-nation by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the deferred balance. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.
In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues effective August 1, 2003 and disallowed
$153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceed-ing be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The BPU also ordered that any expenditures and projects under-taken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L's return on equity to 9.75% or decrease it to 9.25%, depend-ing on its assessment of the reliability of JCP&L's service.
Any reduction would be retroactive to August 1, 2003.
JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculat-ing interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances (2) the capital structure including the rate of return (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs. Management is unable to predict when a decision may be reached by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submit-ted rebuttal testimony on January 4, 2005. Settlement conferences are ongoing.
JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order.
The BGS auction for periods beginning June 1, 2004 was completed in February 2004 and new BGS tariffs reflecting the auction results became effective June 1, 2004. The NJBPU decision on the BGS post transition year three process was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribu-tion companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load. The auc-tion for the supply period beginning June 1, 2005 was completed in February 2005.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a contin-uation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding.
On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study (see Note 11 - Asset Retirement Obligations). This study resulted in an updated total decom-missioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. A schedule for further proceedings has not yet been set.
Pennsylvania 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 FirstEnergy/GPU merger and provided Met-Ed and Penelec PLR deferred accounting treatment for energy costs. A February 2002 Commonwealth Court of Pennsylvania deci-sion affirmed the PPUC decision regarding approval of the merger, remanded the issue of quantification and allocation of merger savings to the PPUC and denied the PLR deferral accounting treatment. In October 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supple-ments to their tariffs which were effective October 2003 FirstEnergy Corp 2004 59
that reflected the CTC rates and shopping credits in effect prior to the June 21, 2001 order.
In response to its October 8, 2003 petition, the PPUC approved June 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds and denied their account-ing request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroac-tive basis. Met-Ed and Penelec subsequently filed with the Commonwealth Court, on October 31, 2003, an Application for Clarification with the judge, a Petition for Review of the PPUC's October 2 and October 16 Orders, and an applica-tion for reargument if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intend-ed to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed January 28, 2005.
In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. These companies' combined portion of total merger savings is esti-mated to be approximately $31.5 million. If no settlement can be reached, Met-Ed and Penelec will take the position that any portion of such savings should be allocated to customers during each company's next rate proceeding.
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is 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 retains 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 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 a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.
Transmission On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($13 deferred as of December 31, 2004 pending authorization) estimated to be incurred from 2004 through 2007. The FERC approved ATSl's request to defer those costs on March 4, 2005.
ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service - for-mula rate included in Attachment 0 under the MISO tariff.
The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 mil-lion. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to eliminate the voltage-differentiated rate design for the ATSI zone.
On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $30 million in transmis-sion and ancillary service costs beginning January 1, 2006.
The Ohio Companies also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, con-gestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approxi-mately $8 million per month.
Various parties have intervened in each of the cases above.
On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC's deci-sion, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmis-sion service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.
- 10. Capitalization (A) COMMON STOCK Retained Earnings and Dividends Under applicable federal law, FirstEnergy (as a regis-tered holding company) and its subsidiaries can pay dividends only from retained, undistributed or current earn-ings, unless the SEC specifically authorizes payment from other capital accounts. As of December 31, 2004, FirstEnergy's unrestricted retained earnings were $1.9 bil-lion. Provisions within the articles of incorporation, indentures and various other agreements relating to the long-term debt and preferred stock of certain FirstEnergy subsidiaries contain provisions that could restrict the pay-ment of dividends on their common and preferred stock. As of December 31, 2004, there were no material restrictions on retained earnings under these agreements for payment of cash dividends on FirstEnergy's common stock.
On November 30, 2004, the Board of Directors increased the indicated annual dividend to $1.65 per share, payable quarterly at a rate of $0.4125 per share, and declared the first quarter 2005 dividend. At December 31, 2004, accrued dividends of approximately $135 million were included in other current liabilities on the Consolidated Balance Sheet. Dividends declared in 2004 were $1.9125 which included quarterly dividends of $0.375 per share paid in each quarter of 2004 and a dividend of $0.4125 payable in the first quarter of 2005. Dividends declared in 2003 were 60 FirstEnergy Corp O004
$1.50, which included quarterly dividends of $0.375 per share paid in each quarter of 2003. The amount and timing of all dividend declarations are subject to the discretion of the Board and its consideration of business conditions, results of operations, financial conditions and other factors.
(B) PREFERRED AND PREFERENCE STOCK All preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice.
CEI will exercise its option to redeem all outstanding shares of two series of preferred stock during the first quar-ter of 2005 as follows:
Series Outstanding Shares Call Price 7.40A 500.000 101.00 L
474.000 100.00 Met-Ed's and Penelec's preferred stock authorizations consist of 10 million and 11.435 million shares, respectively, without par value. No preferred shares are currently out-standing for those companies.
The Companies' preference stock authorization consists of 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding.
(C) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS Preferred Stock Subject to Mandatory Redemption SFAS 150 requires financial instruments issued in the form of shares that are mandatorily redeemable to be classi-fied as long-term debt. Annual sinking fund provisions for the Companies' preferred stock are as follows:
Redemption Price Series Shares Per Share CEI
$ 7.35C 10.000
$100 Penn 7.625%
7,500 100 Annual sinking fund requirements will be satisfied by the end of 2008 and consist of $1.8 million in 2005 and 2006, $12.3 million in 2007 and $1.0 million in 2008.
Subordinated Debentures to Affiliated Trusts As of December 31, 2004, CEl's wholly owned statuto-ry business trust, Cleveland Electric Financing Trust, had
$100 million of outstanding 9.00% preferred securities maturing in 2031. The sole assets of the trust are CEI's sub-ordinated debentures with the same rate and maturity date as the preferred securities.
CEI formed the trust to sell preferred securities and invest the gross proceeds in the 9.00% subordinated debentures of CEI. The sole assets of the trust are the appli-cable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution pay-ment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordi-nated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated deben-tures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. CEI has effectively provided a full and uncondi-tional guarantee of payments due on the trust's preferred securities. The trust's preferred securities are redeemable at 100 percent of their principal amount at CEI's option begin-ning in December 2006. Interest on the subordinated debentures (and therefore distributions on the trust's pre-ferred securities) may be deferred for up to 60 months, but CEI may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred pay-ments on its subordinated debentures are paid in full.
Met-Ed and Penelec had each formed statutory busi-ness trusts for substantially similar transactions to those of CEI, with ownership of the respective Met-Ed and Penelec trusts through separate wholly owned limited partnerships.
In June 2004 and September 2004, respectively, Met-Ed and Penelec extinguished the subordinated debentures held by their respective trusts, who in turn redeemed their respective preferred securities.
Securitized Transition Bonds On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recov-ery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.
JCP&L does not own nor did it purchase any of the transition bonds, which are included in long-term debt on FirstEnergy's Consolidated Balance Sheets. The transition bonds represent obligations only of the Issuer and are collat-eralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bond-able 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 TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with the Issuer.
Other Long-term Debt Each of the Companies has a first mortgage indenture under which it issues FMBs secured by a direct first mort-gage lien on substantially all of its property and franchises, other than specifically excepted property. FirstEnergy and its subsidiaries have various debt covenants under their respec-tive financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. The fixed charge ratio and debt-to-capitalization ratio covenants are applicable to only financing arrangements of FirstEnergy, the Ohio Companies and Penn. There also exist cross-default provisions among financing arrangements of FrstEnergy Corp 2004 61
FirstEnergy and the Companies.
Based on the amount of FMBs authenticated by the respective mortgage bond trustees through December 31, 2004, the Companies' annual sinking fund requirements for all FMBs issued under the various mortgage indentures amounts to $71 million. OE and Penn expect to deposit funds with their respective mortgage bond trustees in 2005 that will then be withdrawn upon the surrender for cancella-tion of a like principal amount of FMBs, specifically authenticated for such purposes against unfunded property additions or against previously retired FMBs. This method can result in minor increases in the amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec expect to fulfill their sinking fund obligations by providing bondable property additions and/or previously retired FMBs to the respective mortgage bond trustees.
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases) for the next five years are:
(In millions),
2005 S 937 2006 1,327 2007 453 2008 470 2009 285 Included in the table above are amounts for various vari-able interest rate pollution control bonds which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $442 million and
$132 million in 2005 and 2008, respectively, representing the next times the debt holders may exercise this provision.
The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of FMBs. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $299 million or noncancelable municipal bond insurance policies of $922 million to pay principal of, or interest on, the applicable pol-lution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.0% to 1.7% of the amounts of the LOCs to the issuing banks and 0.20% to 0.55% of the amounts of the policies to the insurers and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder.
FirstEnergy had unsecured borrowings of $215 million as of December 31, 2004, under its $1 billion revolving cred-it facility agreement which expires June 22, 2007.
FirstEnergy currently pays an annual facility fee of 0.30% on the total credit facility amount. FirstEnergy had no borrow-ings as of December 31, 2004 under a $375 million long-term revolving credit facility agreement, which expires October 23, 2006. FirstEnergy currently pays an annual facil-ity fee of 0.50% on the total credit facility amount. The fees are subject to change based on changes to FirstEnergy's credit ratings.
OE had no unsecured borrowings as of December 31, 2004 under a $250 million long-term revolving credit facility agreement, which expires May 12, 2005. OE currently pays an annual facility fee of 0.20% on the total credit facility amount.
OE had no unsecured borrowings as of December 31, 2004 under a $125 million long-term revolving credit facility, which expires October 23, 2006. OE currently pays an annual facility fee of 0.25% on the total credit facility amount. The fees are subject to change based on changes to OE's credit ratings.
OES Finance, Incorporated, a wholly owned subsidiary of OE, had maintained certificates of deposits pledged as collateral to secure reimbursement obligations relating to certain LOCs supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements.
In June 2004, these LOCs were replaced by a new LOC, which did not require the collateral deposits. OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of the replacement LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE. The certificates of deposit were cancelled and FirstEnergy received cash proceeds of $278 million in the third quarter of 2004.
CEI and TE have unsecured LOCs of approximately $216 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. CEI and TE are jointly and severally liable for such LOCs. OE has LOCs of $294 mil-lion and $154 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively.
- 11. Asset Retirement Obligations In January 2003, FirstEnergy implemented SFAS 143, which provides accounting guidance for retirement obligations associated with tangible long-lived assets. This standard requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retire-ment costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depre-ciated and the present value of the ARO increases, resulting in a period expense. However, rate-regulated entities may recog-nize a regulatory asset or liability instead of an expense if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.
FirstEnergy has identified applicable legal obligations as defined under the standard for nuclear power plant decom-missioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash dispos-al sites. The ARO liability was $1.078 billion as of December 31, 2004 and included $1.063 billion for nuclear decommis-sioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engi-neer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.
62 FirstEnergy Corp. 2004
In the third quarter of 2004, FirstEnergy revised the ARO associated with TMI-2 as the result of a recently completed study and the anticipated operating license extension for TMI-
- 1. The abandoned TMI-2 is adjacent to TMI-1 and the units arc expected to be decommissioned concurrently. The decrease in the present value of estimated cash flows associated with the license extension of $202 million was partially offset by the $26 million present value of an increase in projected decommissioning costs. The net decrease in the TMI-2 ARO liability and corresponding regulatory asset was $176 million.
The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2004, the fair value of the decommissioning trust assets was
$1.583 billion.
The following table describes the changes to the ARO balances during 2004 and 2003.
ARO Reconciliation 2004 2003 (In millions)
Balance at beginning of year
$1,179
$1,109 Liabilities incurred Liabilities settled Accretion 75 70 Revisions in estimated cash flows (1761 Balance at end of year S1.078
$1,179 The following table describes the changes to the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002.
, Adjusted ARO Reconciliation 2002 (In millions)
Beginning balance as of January 1, 2002
$1,042 Accretion 67 Ending balance as of December 31. 2002
$1,109 The following table provides the effect on income as if SFAS 143 had been applied during 2002.
Effect of the Change in Accounting Principle Applied Retroactively (In millions)
Reported net income
$553 Increase IDecrease):
Elimination of decommissioning expense B8 Depreciation of asset retirement cost (3)
Accretion of ARO liability (38)
Non-regulated generation cost of removal component. net 15 Income tax effect (25)
Net earnings increase 37 Net income adjusted
$590 Basic earnings per share of common stock:
Net income as previously reported S1.89 Adjustment for effect of change in accounting principle applied retroactively 0.12 Net income adjusted
$2.01 Diluted earnings per share of common stock:
Net income as previously reported
$1.88 Adjustment for effect of change in accounting principle applied retroactively 0.12 Net income adjusted
$2.00
- 12. Short-Term Borrowings and Bank Lines of Credit:
Short-term borrowings outstanding as of December 31, 2004, consisted of $29 million of OE bank borrowings and
$142 million of OES Capital, Incorporated borrowings. OES Capital is a wholly owned subsidiary of OE whose borrow-ings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.25% on the amount of the entire finance limit. The receivables financing agreement expires in October 2005.
Penn, Met-Ed and Penelec have, through separate wholly owned subsidiaries, receivables financing arrangements that provide a combined borrowing capability of up to $180 mil-lion at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.30% on the entire finance limit. The receivables financing agreements for Penn, Met-Ed and Penelec expire in March 2005. These receivables financing arrangements are expected to be renewed prior to expiration.
OE has various bi-lateral credit facilities with domestic banks that provide for borrowings of up to $34 million under various interest rate options. To assure the availability of these lines, OE is required to pay annual commitment fees that vary from 0.20% to 0.25% of total lender commit-ments. These lines expire at various times during 2005. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2004 and 2003 were 2.35% and 2.14%, respectively.
CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust under an asset-backed securitization agreement. The trust is a "quali-fied special purpose entity" under SFAS 140, which provides it with certain rights relative to the transferred assets. Transfers are made in return for an interest in the trust (62% as of December 31, 2004), which is stated at fair value, reflecting adjustments for anticipated credit losses.
The fair value of CFC's interest in the trust approximates the stated value of its retained interest in the underlying receiv-ables, after adjusting for anticipated credit losses, because the average collection period is 27 days. Accordingly, subse-quent measurements of the retained interest under SFAS 115, (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust.
Of the $222 million sold to the trust and outstanding as of December 31, 2004, FirstEnergy retained interests in
$138 million of the receivables. Accordingly, receivables recorded as other receivables on the Consolidated Balance Sheets were reduced by approximately $84 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2004 totaled approximately $2.5 billion. CEI FirstEnergy Corp. 2004 63
and TE processed receivables for the trust and received servicing fees of approximately $4.8 million in 2004.
Expenses associated with the factoring discount related to the sale of receivables were $3.5 million in 2004.
- 13. Commitments, Guarantees and Contingencies:
(A) NUCLEAR INSURANCE-The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion.
The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retro-spective rating plan would be $402 million per incident but not more than $40 million in any one year for each incident.
The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provid-ed for property damage and decontamination costs. The Companies have also obtained approximately $1.5 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $67.5 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.
The Companies intend to maintain insurance against nuclear risks as long as it is available. To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs.
(B) GUARANTEES AND OTHER ASSURANCES-As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to pro-vide financial or performance assurances to third parties.
Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of December 31, 2004, outstanding guarantees and other assurances aggregated approximately $2.4 billion and includ-ed contract guarantees ($1.0 billion), surety bonds ($0.3 billion) and LOC ($1.1 billion).
FirstEnergy guarantees energy and energy-related pay-ments of its subsidiaries involved in energy commodity activities - principally to facilitate normal physical transac-tions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisi-tion of property, plant and equipment. These agreements legally obligate FirstEnergy 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 counterpar-ty 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 is remote that such parental guarantees of $0.9 billion (included in the $1.0 bil-lion discussed above) as of December 31, 2004 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongo-ing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obliga-tions, subsequent to the occurrence of a credit rating downgrade or "material adverse event" the immediate post-ing of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions as of December 31, 2004:
Collateral Paid Remaining Collateral Provisions Exposure Cash LOC ExposureW (In millions)
Credit rating downgrade 3349 3162 318 3169 Adverse Event 135 22 113 Total 5484
$162
$40 5282 i') As of February 7, 2005, the total exposure decreased to $476 million and the remaining exposure increased to $290 million - net of $146 million of cash collateral and $40 million of LOC collateral provided by counterparties.
Most of FirstEnergy's surety bonds are backed by vari-ous indemnities common within the insurance industry.
Surety bonds and related FirstEnergy guarantees of $279 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commit-ments and various retail transactions.
FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 mil-lion (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee.
FirstEnergy has also provided an LOC (currently at $47 mil-lion), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
(C) ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. 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 that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in com-pliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430 million for 2005 through 2007.
64 FirstErergy Corp. 2004
Clean Air Act Compliance The Companies are required to meet federally approved S02 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for S02 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 complying with S02 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more elec-tricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amend-ments 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' facilities.
The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85 percent reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are con-tributing significantly to ozone levels in the eastern United States. The Companies believe their facilities are also com-plying with the NOx budgets established under State Implementation Plans (SIPs) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine par-ticulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on pro-posed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and S02 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, S02 emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually.
NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.
Mercury Emissions In December 2000, the EPA announced it would pro-ceed with the development of regulations regarding haz-ardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern.
On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two dis-tinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of S02 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year.
The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.
W. H. Sammis Plant In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn.
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. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dat-ing back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address civil penalties and what, if any, actions should be taken to further reduce emis-sions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, 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 consid-er the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's, OE's and Penn's respective financial condi-tion and results of operations. While the parties are engaged FirstEnergy Corp. 2004 65
in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.
Regulation of Hazardous Waste As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently deter-mined 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 PRPs at waste disposal sites, which may require cleanup under the Compre-hensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiat-ed and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2004, 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 SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approxi-mately $65 million as of December 31, 2004. The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies' determination of environ-mental liabilities and are accrued in the period that they are both probable and reasonably estimable.
Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to eco-nomic output - by 18 percent through 2012.
The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on C02 emissions could require significant capi-tal and other expenditures. However, the C02 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-C02 emitting gas-fired and nuclear generators.
Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amend-ments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new per-formance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mor-tality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting compre-hensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the per-formance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.
(D) OTHER LEGAL PROCEEDINGS-Power Outages and Related Litigation In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the caus-es of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inade-quate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceed-ing) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresenta-tion, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the 66 FirstEnergy Corp. 2004
outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of December 31, 2004.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. - Canada Power System Outage Task Force released its final report on the out-ages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand per-ceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a per-ceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organi-zations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the out-ages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommen-dations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recom-mends be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outage. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system.
FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received inde-pendent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Note 9). FirstEnergy's implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its continuing operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend addi-tional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.
Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of juris-diction. One case was refiled at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.
One complaint has been filed against FirstEnergy in the New York State Supreme Court. In this case, several plain-tiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No timetable for a deci-sion on the motion to dismiss has been established by the Court. No damage estimate has been provided and thus potential liability has not been determined.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
Nuclear Plant Matters FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury inves-tigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assess-ment of reactor head management issues at Davis-Besse.
In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to enforcement action based on the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear Power Firs tEnergy Corp. 2004 67
Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased over-sight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's correc-tive actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.
Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below.
Various legal proceedings alleging violations of federal secu-rities laws and related state laws were filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and the Ohio Companies of previ-ously reported results, the August 14, 2003 power outages described above, and the extended outage at the Davis-Besse Nuclear Power Station. The lawsuits were filed against FirstEnergy and certain of its officers and directors. On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve these pending lawsuits. The settlement agreement, which does not constitute any admission of wrongdoing, pro-vides for a total settlement payment of $89.9 million. Of that amount, FirstEnergy's insurance carriers paid $71.92 million, based on a contractual pre-allocation, and FirstEnergy paid
$17.98 million, which resulted in an after-tax charge against FirstEnergy's second quarter 2004 earnings of $11 million or
$0.03 per share of common stock (basic and diluted). On December 30, 2004, the court approved the settlement.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restate-ments and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
If it were ultimately determined that FirstEnergy or its sub-sidiaries have legal liability or are otherwise made subject to liability based on the above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial con-dition and results of operations.
- 14. Segment Information:
FirstEnergy has three reportable segments: regulated services, competitive electric energy services and facilities (HVAC) services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of international businesses that have subsequently been divested, MYR (a construction service company); natural gas operations and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable segments."
FirstEnergy's primary segment is its regulated services seg-ment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey. The competitive electric energy services business segment primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 2(A) -
Accounting for the Effects of Regulation).
The regulated services segment designs, constructs, oper-ates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from elec-tricity delivery and transition costs recovery. The regulated services segment assets include generating units that are leased to the competitive electric energy services. Its internal revenues repre-sent the rental revenues for the generating unit leases.
The competitive electric energy services segment has responsibility for FirstEnergy generation operations as discussed under Note 2(A). Its net income is primarily derived from rev-enues from all electric generation sales revenues consisting of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets and the related costs of electricity generation and sourcing of commodity requirements.
Its net income also reflects the expense of the intersegment generating unit leases discussed above and property tax amounts related to those generating units.
Segment reporting for 2003 and 2002 was reclassified to conform with the current year business segment organization and operations emphasizing FirstEnergy's regulated electric busi-nesses and competitive electric energy operations. A previous reportable segment was the more expansive competitive servic-es segment whose aggregate operations consisted of FirstEnergy generation operations, natural gas commodity sales, providing local and long-distance phone service and other com-petitive energy related businesses such as facilities services and construction service (MYR) which was viewed as offering a com-prehensive menu of energy related services. Management's focus is on its core electric business. This has resulted in a change in performance review analysis from an aggregate view of all competitive services operations to a focus on its competi tive electric energy operations. During FirstEnergy's periodic review of reportable segments under SFAS 131, that change resulted in the revision of reportable segments to the separate reporting of competitive electric energy operations, facilities serv-6S FirsrEnergy Corp..?004
ices and including all other competitive services operations in th "Other" segment. Facilities services is being disclosed as a reporting segment due to the subsidiaries qualifying as held for sale (see Note 2 (H)). In addition, certain amounts (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year.presentation of generation commodity costs. Interest expense on holding com-pany debt and corporate support services revenues and expenses are now included in "Reconciling Items" and "Other' includes those operating segment results described above.
6&
Products and Services' Energy Related Year Electricity Sales Sales and Services (In millions) 2004
$10.831
$745 2003 10.205 766 2002 9,656 904
- See Note 2(J) for discussion of discontinued operations.
Segment Financial Information Corpetitive EIbctvic Regulated Energy Services Services Fscilites Reconciling Services Other Adiupxneets Cmnsolidated (In millions) 2004 External revenues Internal revenues Total revenues Depreciation and amortization Goodwill impairment Net interest charges Income taxes Income before discontinued operations Discontinued operations Net income Total assets Total goodwill Property additions
$5.395 318 5,713 1.422 363 740 1,015 1,015 28,341 5.951 572
$6,204 6,204 35 37 72 104 104 1,488 24 245
$398
$451 S 5 (318) 398 451 (3131 5
36 1101 136) 136) 135 3
3 14 (24) 41 4
45 625 75 4
34 252 (107)
(250)
(2501 479 21
$12,453 12,453 1,499 36 667 671 874 4
878 31,068 6,050 846 r
2003 External revenues Internal revenues Total revenues Depreciation and amortization Goodwill impairment Net interest charges Income taxes Income before discontinu operations and cumulativ effect of accounting change Discontinued operations Cumulative effect of accounting change Net income Total assets Total goodwill Property additions 55,253 319 5.572 1.423 493 779
$55487 5,487 29 44 (2221
$327 5564 327 564 2
117 1
107 135) (18)
$44 (3191 (2751 38 164 196)
(180) 511,675 11,675 1.492 117 809 408 424 1103) 102 423 32,910 6,128 856 Geographic Information Following the sales of international operations in 2002 through January of 2004, less than one percent of FirstEnergy's revenues and assets were in foreign countries in 2003 and 2004. See Note 8 for a discussion of the divestitures.
- 15. New Accounting Standards and Interpretations SFAS 153, 'Exchanges of Nonmonetary Assets -
an amendment of APB Opinion No. 29" In December 2004, the FASB issued this Statement amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this state-ment are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on the financial statements.
SFAS 123 (revised 2004) 'Share-Based Payment" In December 2004, the FASB issued this revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new stan-dard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain crite-ria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensa-tion. The effective date for FirstEnergy is July 1, 2005 and the Company will be applying modified prospective applica-tion, without restatement of prior interim periods. Any potential cumulative adjustments have not been deter-mined. FirstEnergy uses the Black-Scholes option-pricing model to value options and will continue to do so upon adoption of SFAS 123(R). The impacts of the fair value recognition provisions of SFAS 123 on FirstEnergy's net 1.063 (320) 175) (64)
(6) 197) 101 1
1.164 (320)
(81) (160) 29.789 1,423 166 912 5.993 24 36 75 434 335 4
9 (180) 620 74 2002 External revenues
$55298
$4.825
$383
$907
$40
$11,453 Internal revenues 318 (318)
Total revenues 5.616 4.825 383 907 (278) 11.453 Depreciation and amortization 1,413 24 6
2 34 1,479 Net interest charges 588 43 2
134 189 956 Income taxes 722 (88) 2 114) (1081 514 Income before discontinued operations 962 (170) 21 (1951 618 Discontinued operations 3
168)
(65)
Net income 962 (170) 3 147) (1951 553 Total assets 30,494 1,340 402 1.606 544 34,386 Total goodwill 5.993 24 196 65 6.278 Property additions 490 391 6
9 102 998 Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consists of interest expense related to holding company debt corporate support services revenues and expenses, fuel marketing revenues, which are reflected as reductions to expenses for internal management reporting purposes and elimination of intersegment transactions.
FirstEnergv Corp. 2004 69
income and earnings per share for 2002 through 2004 are disclosed in Note 4. FirstEnergy is considering alternative compensation strategies in conjunction with the adoption of SFAS 123(R).
SFAS 151, 'Inventory Costs - an amendment of ARB No. 43, Chapter 4" In November 2004, the FASB issued this statement to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circum-stances these costs may be "so abnormal" that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of con-version be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy after June 30, 2005.
FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments' In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired.
When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.
EITF Issue No. 03-16, "Accounting for Investments in Limited Liability Companies-In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a lim-ited liability company that maintains a "specific ownership account" for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by FirstEnergy in the third quarter of 2004 and did not affect the Companies' financial statements.
FSP 109-1, 'Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004" Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation At of 2004 (Act) that provides a tax deduction on qualified pro-duction activities. The Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) "qualified production activities income," as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limit-ed to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109, "Accounting for Income Taxes." FirstEnergy is currently eval-uating this FSP but does not expect it to have a material impact on the Company's financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employ-ers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal sub-sidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on FirstEnergy's consolidated financial statements is described in Note 3.
- 16. Summary of Quarterly Financial Data (Unaudited):
The following summarizes certain consolidated operating results by quarter for 2004 and 2003. Certain financial results have been reclassified from amounts previously reported due to FES' natural gas business qualifying as held for sale in accordance with SFAS 144 as discussed in Note 2(J).
1 March 31, June 30, Sept 30.
2004 2004 2004 Three Months Ended Dec. 31, 2004 1
ufnts) i
{In millions, except per share ame Revenues 53.027
$3,041
$3.435
$2,950 Expenses 2,568 2,481 2,771 2,421 Income Before Interest and Income Taxes 459 560 664 529 Net Interest Charges 171 180 151 165 Income Taxes 115 177 215 163 Income Before Discontinued Operations 173 203 298 201 Discontinued Operations INet of Income Taxes) 1 1
1 1
Net Income
$174
$204
$299 S202 Basic Earnings Per Share of Common Stock:
Before Discontinued Operations S0.53 SO.62
$0.91
$0.61 Discontinued Operations Basic Earnings Per Share of Common Stock SO.53
$0.62
$0.91
$0.61 Diluted Earnings Per Share of Common Stock:
Before Discontinued Operations. $0.53
$0.62
$0.91
$0.61 Discontinued Operations Diluted Earnings Per Share of Common Stock
$0.53
$0.62
$ 0.91
$0.61 70 FrustEnergy Corp 2004
March 31.
June 30, Sept 30.
Dec. 31, ThreeMonthsEnded 2003
.2003 2003
- 2003 (In millions. except per share amounts)
Revenues 52.981 52.728
-3.317 S2.649 Expenses 2.571 2,488 2,833 2,310 Claim Settlement (Note 8) 168 I Income Before Interest and Income Taxes 410 240 484 507 Net Interest Charges 205 205 200 199 IncomeTaxes 93 21 134 160 Income Before Discontinued Operations and Cumulative Effect of Accounting Change 112 14 150 148 Discontinued Operations (Net of Income Taxes) 5 (72) 2 (38)
Cumulative Effect of Accounting Change (Net of Income Taxes) 102 Net Income (Loss)
S 219 S (58)
. $ 152 S 110 Basic Earnings (Loss) Per Share of Common Stock:
Before Discontinued Operations and Cumulative Effect of Accounting Change S 0.38 S 0.05
$ 0.51 S 0.45 Discontinued Operations 0.01 (0251 (0.121 Cumulative Effect of Accounting Change 0.35 Basic Earnings (Lossl Per Share of Common Stock S 0.74 510.20)
S 0.51
$ 0.33 Diluted Earnings (Loss)
Per Share of Common Stock:
Before Discontinued Operations and Cumulative Effect of Accounting Change S 0.38
$ 0.05 S 0.50 S 0.45 Discontinued Operations 0.01 (0.25)
(0.12)
Cumulative Effect of Accounting Change 0.35 Diluted Earnings (Loss)
Per Share of Common Stock S 0.74 5(0.20)
S 0.50
$ 0.33 Results in the second quarter of 2004 included FirstEnergy's sale of its 50 percent interest in GLEP, which produced an after-tax loss of $7 million, or $0.02 per share (see Note 8). Third quarter 2004 results were impacted by a
$17 million net-of-tax, or $0.05 per share charge for losses and impairments relating to the divestiture of certain non-core, technology-related investments. Fourth quarter 2004 results included a $37 million net-of-tax, or $0.11 per share, non-cash charge for impairment of goodwill and other assets of FSG as required by SFAS 142 and SFAS 144 (see Note 2 (H)).
The net loss for the second quarter of 2003 included a charge resulting from the NJBPU's decision to disallow recovery by JCP&L of $153 million in deferred energy costs and a $67 million non-cash charge (no tax benefit recog-nized) from the abandonment of operations in Argentina.
Results for the fourth quarter of 2003 included a $33 million after-tax loss from the divestiture of assets in Bolivia reported as discontinued operations and a $26 million impairment of the equity TEBSA investment in Columbia included in continuing operations. The fourth quarter 2003 results also include a $170 million gain ($168 million net of expenses) from the NRG Energy Inc. settlement claim.
FirstEnergy Corp. 2004 71
CONSOLIDATED FINANCIAL AND PRO FORMA COMBINED OPERATING STATISTICS (Unaudited) (see Note 2(J))
(Dollars in thousands}
2004 2003 2002 2001 2000 1999 1994 General Financial Information Revenues
$12,453,046
$11,674,888
$11,453,354
$ 7,237,011 S 6,470,488 $ 6,130,004
$2,390,957 Net Income
$ 878,175 S 422,764
$ 552,804
$ 646,447
$ 598,970
$ 568,299
$ 281,852 SEC Ratio of Earnings to Fixed Charges 2.60 1.73 1.88 2.22 2.10 2.01 2.24 Capital Expenditures
$ 731,342
$ 791,834
$ 903,606
$ 887,929
$ 568,711
$ 474,118
$ 258,642 Total Capitalization (a)
$18,937,766
$18,413,530
$18,686,388 S21,339,001
$11,204,674
$11,469,795
$5,852,030 Capitalization Ratios a):
Common Stockholders' Equity 45.3%
45.0%
37.7%
34.7%
41.5%
39.8%
39.6%
Preferred and Preference Stock:
Not Subject to Mandatory Redemption 1.8 1.8 1.8 2.2 5.8 5.7 5.6 Subject to Mandatory Redemption 2.3 2.8 1.4 2.2 0.7 Long-Term Debt 52.9 53.2 58.2 60.3 51.3 52.3 54.1 Total Capitalization 100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
Average Capital Costs:
Preferred and Preference Stock 6.51%
6.47%
7.50%
7.90%
7.92%
7.99x 7.15' Long-Term Debt 5.93x 6.08%
6.56%
6.98%
7.84%
7.65X 8.17%
Common Stock Data Earnings per Share Ibl Basic
$2.67
$1.40
$2.11
$2.85
$2.69
$2.50
$1.97 Diluted
$2.66
$1.40
$2.10
$2.84
$2.69
$2.50
$1.97 Return on Average Common Equity Ib) 10.4%
5.7%
8.2%
12.9%
13.0%
12.7%
12.4%
Dividends Paid per Share
$1.50
$1.50
$1.50
$1.50
$1.50 S1.50
$1.50 Dividend Payout Ratio(b) 56%
107%
71%
53%
56%
60%
76%
Dividend Yield 3.8%
43%
4.5%
4.3%
4.8%
6.6%
8.1' Price/Earnings Ratio bl 14.8 25.1 15.6 12.3 11.7 9.1 9.4 Book Value per Share
$26.20
$25.35
$24.01
$25.29
$21.29
$20.22
$16.15 Market Price per Share
$39.51
$35.20
$32.97
$34.98
$31.56
$22.69
$18.50 Ratio of Market Price to Book Value 151%
139%
137%
138%
148%
112%
115' Operating Statistics (0 Generation iGlfwatt-Hour Sales (Millonsk Residential 31,781 31,322 31,937 32,708 32,519 32,616 29,969 Commercial 32,114 32,311 32,892 32,170 33,139 30,311 27,667 Industrial 31,675 32,451 32,726 33,024 31,140 30,422 33,893 Other 504 554 531 536 522 566 1,454 Total Retail 96,074 96,638 98,086 98,438 97,320 93,915 92,983 Total Wholesale 53,268 42,059 30,007 20,240 13,761 14,631 9,389 Total Sales 149,342 138,697 128,093 118,678 111,081 108,546 102,372 Customers Served:
Residential 3,916,855 3,874,052 3,868,499 3,833,013 3,798,716 3,767,534 3,615,157 Commercial 500,695 496,253 471,440 464,053 472,410 455,919 422,468 Industrial 10,597 10,871 18,416 18,652 18,996 19,549 21,087 Other 5,654 5,635 5,716 5,762 6,001 5,992 7,468 Total 4,433,801 4,386,811 4,364,071 4,321,480 4,296,123 4,248,994 4,066,180 Number of Employees 15,245 15,905 17,560 18,700 18,912 19,470 22.488 Id 2001 capitalization includes approximately S1.4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in 'Liabilities Related to Assets Pending Sale' on the Consolidated Balance Sheet as of December 31. 2001.
lb Before discontinued operations in 2004, 2003 and 2002 and accounting changes in 2003 and 2001.
Icd Reflects pro forma combined FirstEnergy and 6PU statistics in the years 1999 to 2001 and pro forma combined Ohio Edison, Centerior and GPU statistics in years prior to 1999.
72 FirstEnergy Corp. 2004
Shareholder Information Shareholder Services, Transfer Agent and Registrar FirstEnergy Securities Transfer Company, a subsidiary of FirstEnergy, acts as our own transfer agent and registrar for all stock issues of FirstEnergy and its subsidiaries. Shareholders wanting to transfer stock, or who need assistance or information, can send their stock or write to Shareholder Services, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. Shareholders also can call the following tollfree telephone number, which is valid in the United States, Canada, Puerto Rico and the Virgin Islands, weekdays between 8 a.m. and 4:30 p.m., Eastern Time: 1-800-736-3402.
For Internet access to general shareholder information and useful forms, visit our Web site at www.frstenergycorp.conmlr.
Stock Listings and Trading Newspapers generally report FirstEnergy common stock under the abbreviation FSTENGY, but this can vary depending upon the news-paper. The common stock of FirstEnergy and preferred stock of its electric utility subsidiaries are listed on the following stock exchanges:
Combining Stock Accounts If you have more than one stock account and want to combine them, please write or call Shareholder Services and specify the account that you want to retain as well as the registration of each of your accounts.
Stock Investment Plan Shareholders and others can purchase or sell shares of FirstEnergy common stock through the Company's Stock Investment Plan.
Investors who are not registered shareholders can enroll with an initial $250 cash investment. Participants may invest all or some of their dividends or make optional cash payments at any time of at least S25 per payment up to $100,000 annually. Contact Shareholder Services to receive an enrollment form.
Safekeeping of Shares Shareholders can request that the Company hold their shares of FirstEnergy common stock in safekeeping. To take advantage of this service, shareholders should forward their common stock certifi-cate($) to the Company along with a signed letter requesting that the Company hold the shares. Shareh6lders also should state whether future dividends for the held shares are to be reinvested or paid in cash. The certificate(s) should not be endorsed, and registered mail is suggested. The shares will be held in uncertificated form, and we will make certificate(s) available to shareholders upon request at no cost. Shares held in safekeeping will be reported on dividend checks or Stock Investment Plan statements.
Company Stock Exchange Symbol FirstEnergy New York Jersey Central New York Ohio Edison New York Pennsylvania Power Philadelphia Toledo Edison New York, OTC American FE JYP OEC PPC TED Dividends Proposed dates for the payment of FirstEnergy common stock dividends in 2005 are:
I Ex-Dividend Date Record Date Payment Date j February 3 February 7 May 4 May 6 August 3 August 5 iNovember 3 November 7 March 1 i
June 1 A
September 1 December 1 i
Form 10-K Annual Report Form 10-K, the Annual Report to the Securities and Exchange Commission, will be sent without charge by writing to David W.
Whitehead, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890.
Institutional Investor and Security Analyst Inquiries Institutional investors and security analysts should direct inquiries to:
Kurt E. Turosky, Director, Investor Relations, 330-384-5500.
Annual Meeting of Shareholders Shareholders are invited to attend the 2005 Annual Meeting of Shareholders on Tuesday, May 17, at 10:30 a.m. Eastern Time, at the John S. Knight Center, 77 East Mill Street, in Akron, Ohio.
Registered shareholders not attending the meeting can appoint a proxy and vote on the items of business by telephone, Internet or by completing and returning the proxy card that is sent to them.
Shareholders whose shares are held in the name of a broker can attend the meeting if they present a letter from their broker indicating ownership of FirstEnergy common stock on the record date of March 22, 2005.
All dividends are subject to declaration by the Board of Directors at its discretion.
Direct Dividend Deposit Shareholders can have their dividend payments automatically deposited to checking and savings accounts at any financial institu-ton that accepts electronic direct deposits. Use of this free service ensures that payments will be available to you on the payment date, eliminating the possibility of mail delay or lost checks. Contact Shareholder Services to receive an authorization form.
FirstEnergy has included as Exhibit 31 to its Annual Report on Form 10-K for fiscal year 2004 filed with the Securities and Exchange Commission certificates of FirstEnergy's Chief Executive Officer and Chief Financial Officer certifying the quality of the Company's public disclosure. ForstEnergy's Chief Executive Officer has also submitted to the New York Stock Exchange (NYSE) a certificate certifying that he was not aware of any violation by FrstEnergy of the NYSE corporate governance listing standards as of the date of the certification.
Printed on recycled paper firstEneTy Corp. 2004 73
FirstEqpjy 76 South Main Street, Akron, OH 44308-1890 www.firstenergycorp.com PRESORTED STD.
U.S. POSTAGE PAID AKRON, OHIO PERMIT NO. 561 2004 Annual Report