ML003696217
| ML003696217 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley, Davis Besse, Perry |
| Issue date: | 03/17/2000 |
| From: | Scilla R FirstEnergy Nuclear Operating Co |
| To: | Dinitz I Office of Nuclear Reactor Regulation |
| References | |
| -RFPFR, DB-No.-2649, PY-CEI/NRR-2478L | |
| Download: ML003696217 (54) | |
Text
76 South Main Street Akron, Ohio 44308-1890 330-384-5202 iandy ScTlau March 17, 2000 Fax: 330-384-3772 Assistant Treasurer PY-CEI/NRR-2478L DB-No.-2649 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 FirstEnergy Corp. (parent of The Cleveland Electric Illuminating Company, The Toledo Edison Company, Ohio Edison Company, and Pennsylvania Power Company) hereby provides the documents described below as evidence of its guarantee of the retrospective premiums which may be served against the Davis-Besse Unit No. 1 ($10,000,000), Perry Unit No. 1
($10,000,000), Beaver Valley Unit No. 1 ($10,000,000) and Beaver Valley Unit No. 2 ($10,000,000) reactor licenses, per Section 140.21 of 10 CFR Part 140.
(1) FirstEnergy Corp. Annual Report for 1999 (2) A 2000 Internal Cash Flow Projection for FirstEnergy Corp.
certified by the Assistant Treasurer of the Company.
Very truly yours, cl Enclosures
FIRSTENERGY CORP.
2000 INTERNAL CASH FLOW PROJECTION FOR DAVIS-BESSE UNIT NO. 1, PERRY UNIT NO. 1, AND BEAVER VALLEY UNIT NOS. 1 AND 2 NUCLEAR POWER PLANTS (Dollars in Thousands) 2000 Proiected Cash Flows:
Retained Earnings, Depreciation and Amortization
$1,416,000 Deferred Income Taxes and Investment Tax Credits (182,000)
Allowance for Funds Used (11,000)
During Construction and Carrying Charges Deferred Operating Expenses (65,000)
Net Cash Flows
$1,157,000 Internal Cash Flow
$1,157,000 Average Quarterly Cash Flow
$289,000 Percentage Ownership in Units:
Davis-Besse Unit No. 1 100.00%
Perry Unit No. 1 100.00%
Beaver Valley Unit No. 2 100.00%
Beaver Valley Unit No. 1 100.00%
Maximum Total Contingent Liability
$40,000 CERTIFICATION I, Randy Scilla, Assistant Treasurer of FirstEnergy Corp., hereby certifies that the foregoing Internal Cash Flow Projection for calendar year 2000 is derived from reasonable assumptions and is a reasonable estimate.
/Date
/6andy Scilla Shr TresFinancial Studies\\jnum\\NRC Filing-cl.doc or CALMNRC-Filing-cl.doc
999 ANNUAL TAKING REP 0 RT ON THE COMPETITION FirstEnergy 1
-5 5
Id I ý 41
Financial H tG-H L I GH T S STRATEGIC VISION FirstEnergy will be the leading regional retail energy and related services supplier; the preferred choice for total customer solutions; the shareholder's choice for long term growth and investment value; and a Company that is driven by the skills, diversity, flexibility and character of its employees.
MISSION STATEMENT FirstEnergy will provide competitively priced, high quality products and value-added services in:
"* Energy sales and services
"* Energy delivery
"* Power supply
"* Regulated and unregulated supplemental services related to our core business STRATEGY To achieve our vision we will:
"* Maximize the value of core operations
"* Position the Company for profitable growth in related areas
"* Maximize value retention during the transition to competition
"* Increase financial flexibility and investor confidence CONTENTS Message to Shareholders Year in Review 1999 (Dollars in thousands, except per share amounts)
Total revenues
$6,319,647 Income before extraordinary charge
$568,299 Earnings per common share:
Before extraordinary charge
$2.50 After extraordinary charge
$2.50 Return on average common equity*
12.7%
Dividends per common share
$1.50 Book value per common share
$20.22 Common equity to total capitalization 39.8%
Cash provided by operating activities
$1,488,306
- Before extraordinary charge in 1998 Book Value Per Share s20.22 s19.37
$18.71 s17.35
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'97
'98
'99 1998
$5,874,906
$441,396
$1.95
$1.82 10.3%
$1.50
$19.37 37.9%
$1,155,325 Earnings Per Share
- Before extraordinary charge 2
4 Directors and Management 14 Management's Discussion and Analysis 18 Shareholder Information 49 I
A Message to S HARE H O L-D.E RS We're taking on the competition. With the nation's tenth largest investor-owned electric system, expanding natural gas resources and the Midwest's largest provider of facilities services, FirstEnergy is achieving its vision of becoming the region's premier retail energy and related services supplier.
In 1999, we entered deregulated electricity markets in Pennsylvania, New Jersey and Delaware, where we're adding thousands of new customers, including more than 800 federal facilities, such as the Statue of Liberty. We're expanding our natural gas operations, with 44,000 new customers added last year, and are con tinuing to grow our Facilities Services Group, which provides mechanical contracting, facilities management, and energy management services to customers nationwide.
By the end of 2000, we expect to produce approximately $1.5 billion in annual revenues from these unregulated activities. At the same time, we're sharpening our skills to retain and expand our customer base in Ohio, where all consumers can select their electricity supplier beginning January 1, 2001, and in other states as opportunities arise.
DELIVERING STRONGER EARNINGS PERFORMANCE Growth in retail sales, lower purchased power costs and continued savings from our debt-reduction and refinancing activities contributed to stronger earnings performance in 1999.
We earned $568.3 million, or $2.50 per share of common stock for the year, a 38-percent increase from 1998 net income of $410.9 million, or $1.82 per share. Earnings in 1998 included a one-time charge of 13 cents per share that resulted from the deregulation of Pennsylvania's electric generation business.
The increase in earnings reflects our seventh consecutive year of growth in regulated retail kilowatt-hour sales.
Residential sales increased 6.7 percent, commercial sales rose 3.9 percent, and sales to industrial customers were up 3.4 percent. Total regulated and unregulated electric sales increased 8.9 percent, reflecting a 28.4 percent rise in power sales to other utilities and new sales in deregulated energy markets.
Improved operations and cost-control efforts also contributed to higher earnings. We reduced purchased power costs by nearly $126 million, mainly due to the increased availability of our generating units. We also redeemed or refinanced $888 million in securities, which will produce about $50 million in annual savings.
In addition, we repurchased approximately six million shares of our outstanding common stock. We intend to purchase up to 15 million shares by the end of 2001 to improve our long-term financial performance.
We're also strengthening our performance by setting goals and planning our operations in terms of their potential for creating value. To assess the true value of investments and changes in operating activities, we use Shareholder Value Added (SVA) - a measurement of net profit after taxes and the cost of capital. Last year, SVA improved by $166 million compared with 1998 results.
Despite these achievements, higher interest rates and uncertainty about the impact that competition will have on our industry have depressed the value of our common stock, and the stock of electric utilities nationwide.
We can't predict future market performance. However, we believe a favorable resolution of competitive issues in Ohio will have a positive effect on our common stock.
PREPARING FOR COMPETITION IN OHIO While Ohio's new electric utility restructuring law gives consumers the opportunity to choose their electricity supplier, it also gives us the opportunity to continue recovering costs we had expected to recover in future years under the current regulatory structure.
We've filed for recovery of $6.97 billion, which includes credits to customers for such items as deferred income taxes, in our proposed transition plan submitted to the Public Utilities Commission of Ohio (PUCO). The 11,000-page filing is the first step in a complex process that will determine unbundled prices for the services we provide; how we will separate our regulated and unregulated businesses; and rules for how we and other suppliers will operate in a competitive environment.
We believe our rationale for recovery of transition costs is solid. The PUCO is expected to reach a decision on our plan this summer.
ACHIEVING OUR VISION For nearly a decade, we've been taking the necessary steps to prepare for competition, most notably the 1997 merger of Ohio Edison and Centerior Energy that formed FirstEnergy.
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Since then, we've transformed FirstEnergy from an electric utility holding company into a diversified energy services enterprise equipped to meet all of our customers' energy needs.
Key operational milestones in our core electric business are contributing to our progress. For instance, last year we gained exclusive ownership and operational control of the 1,630-megawatt Beaver Valley Power Station and nine generating units that we had jointly owned with other electric utility companies.
We're aggressively working to bring Beaver Valley's performance in line with that of our other nuclear plants - Perry and Davis-Besse - which are among the world's top performers.
Our employees' ongoing commitment to operational excellence resulted in another year of impressive performance in productivity, safety and customer service. The reliable operation of our generating units significantly reduced our need to purchase costly power during periods of peak customer demand and enabled us to make highly profitable electricity sales on the wholesale market.
We did so while keeping employee safety a top priority. Operations employees at Davis-Besse marked their twentieth year without a lost-time accident. In addition, our ongoing emphasis on safety helped us achieve a 34-percent improvement in a key Occupational Safety and Health Administration measurement. That puts our safety record on track to rank among the top utility companies in the Edison Electric Institute's annual safety survey that will be released later this year.
Significant accomplishments weren't limited to our core electric business.
We now serve approximately 50,000 natural gas customers in the Midwest following our acquisitions of Atlas Gas Marketing, Inc., located near Pittsburgh, Pennsylvania; Volunteer Energy, L.L.C., of Columbus, Ohio; and Belden Energy Services Company of North Canton, Ohio.
We greatly expanded our natural gas resources by combining our properties and pipelines in the Appalachian Basin with Range Resources Corporation's Appalachian properties through a new joint venture called Great Lakes Energy Partners, L.L.C.
And, the continued growth of our Facilities Services Group's customer base is enhancing our opportunities to sell electricity and natural gas outside our traditional service area.
ADDRESSING A U.S. EPA ACTION Despite spending more than $4 billion to ensure that our power plants comply with environmental regulations, the U.S. Environmental Protection Agency (U.S. EPA) has taken legal action against our W. H. Sammis Plant - along with 43 plants in the Midwest and South owned by other electric utilities alleging that it has violated the Clean Air Act. New York and Connecticut have taken steps to join the U.S. EPA action, blaming the plants for pollution in the Northeast.
The U.S. EPA claims that maintenance, repairs and replacements conducted since 1984 - some under the agency's own oversight - now trigger provisions of the Act that require additional environmental controls, even though generating capacity and emissions have not increased.
We believe that this is a misinterpretation of the Clean Air Act, and we remain confident that the Sammis Plant is in full compliance with the law.
TAKING ON TIlE COMPETITION Sales of electricity in deregulated markets, natural gas and facilities services are diversifying our revenue sources and helping us better meet all our customers' energy needs. This strategy has positioned us to take on the competition in the northeast quadrant of the United States - the region we've targeted for growth.
A good deal of the credit for the progress we've made goes to Willard R. Holland, who retired on December 31 as Chairman of your Board. I'm sure you'll join me in wishing Will the best in his retirement.
With your ongoing support, and the hard work of our employees, we'll continue capitalizing on opportunities and taking on challenges in the increasingly competitive energy marketplace.
Sincerely, H. Peter Burg C, Chairman and Chief Executive Officer March 8, 2000 3
Preparing for COMPETITION After years of debate, Ohio enacted a new law last year that will enable consumers to change their electricity supplier beginning January 1, 2001, the start of a five year market development period, and the beginning of a transition period that could last through 2010.
The law opens the power generation portion of the electric utility industry to competition. While cus tomers can choose a dif ferent electricity supplier, our electric utility operating companies will continue to deliver electricity, and will provide other regu lated services within our traditional service area.
Under the law, we filed a transition plan with the Public Utilities Commission of Ohio (PUCO) that details how we plan to move from regulation to competition. The plan includes proposals for:
Unbundling the price of electricity into its component elements
- primarily genera tion, transmission, distribution and tran sition charges in Ohio
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Corporate separation of our regulated and unregulated businesses
"* Operational and tech nical support, including changes to customer billing, metering and accounting to accommodate new electricity suppliers
"* Tariff terms and condi tions for customers who choose a new supplier
"* Assistance for utility employees whose jobs are affected by the new law
"* Consumer education to help customers better understand their options
"* Independent operation of our transmission system to ensure fair and equal access for all electricity suppliers The plan also seeks recovery of $6.97 billion in transition costs, including credits to customers for such items as deferred income taxes. In general, transition costs were incurred to meet govern ment policies, practices or mandates under the exist ing regulatory structure.
Recovery of these costs will not increase the price customers currently pay for electricity. Under our plan, most transition costs would be recovered by the end of 2005, with recovery of remaining costs continuing up through 2010. The PUCO is expected to rule on our plan this summer.
We're also repositioning our transmission business in preparation for competition. We received approval from the Federal Energy Regulatory Commission (FERC) to transfer our transmission assets - with an original cost of $1.2 billion - to a subsidiary, American Transmission Systems, Inc. (ATSI).
Upon receipt of other regulatory approvals, our high-voltage transmission facilities would be trans-ferred to ATSI. They include approximately 7,100 miles of transmission lines with voltages of 69,000 and higher; 130 transmission substations; and 37 interconnections with 6 other electric companies.
The transfer would be the first step toward our participation in a regional transmis sion organization (RTO), an entity that would operate and ultimately could own the transmission sys tem. We're working to create such an organization called the Alliance RTO - with American Electric Power, Consumers Energy, Detroit Edison and Virginia Power.
FERC has conditionally approved our proposed formation of this RTO, through which member companies will consolidate control and operation of their transmission systems, while ensuring that users have non-discriminatory access to the transmission grid.
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,sl. stutiolU; (I 345. O00-z.,o tU.ccrF: the Ohio stareloose ill Total Revenues
($ Millions)
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Regulated I j Unregulated
Achieving Ongoing improvements in our core electric busi ness are preparing us for competition in Ohio and are helping us succeed in new markets.
Among our most significant accomplishments in 1999 was the completion of our asset transfer with Duquesne Light Company of Pittsburgh. This trans action gave us exclusive ownership and operating control of the power plants we had jointly owned, and better positions us to maximize their value.
We exchanged our Avon Lake, Niles and New Castle plants for Duquesne's share in the Beaver Valley, Sammis, Eastlake, Mansfield and Perry plants, increasing our system capacity by a net 108 megawatts (MW).
Gaining operational control of Beaver Valley enables us to bring its Operational EXCELLENCE performance in line with our other nuclear plants Davis-Besse and Perry which are among the industry's top performers.
The plants are operated by FirstEnergy Nuclear Operating Company (FENOC) under which we've consolidated management of our nuclear operations to improve reliability, safety and efficiencies.
We're already seeing positive results. In 1999, the Perry Plant completed the shortest refueling outage in its history, and in January of 2000 surpassed its longest on-line run of 266 days.
In addition, through year end, Perry and Davis-Besse employees worked 1.7 and 2.5 million hours, respectively, without a lost-time accident.
Our coal-fired plants made impressive improvements as well, including an operating (Rgbht) We notw ha.ve exclusive ownership of the Beaver Valley (foreground) and Bruce Mansfield plants; (far lqft, clockwise) mon itoring operations at our Svsteiz Control Center, turbine inspection:
coal barge on the Ohio River.
availability of 87.6 percent, which significantly lowered our purchased power costs.
Our Occupational Safety and Health Administration incident rate of 1.66 per 100 utility employees represents a 34-percent improvement over 1998.
As a result, we expect our safety record to rank near the top of the Edison Electric Institute's annual safety survey of electric utility companies nationwide that will be released later this year.
We're also increasing our peaking capacity to better serve new and existing customers and to further reduce purchased power costs.
We added 87 MW of peaking capacity by acquiring GPU, Inc.'s minority share of our 435-MW Seneca Pumped Storage Hydroelectric 6
Generating Station located in western Pennsylvania.
And, we're installing three, 130-MW, natural-gas-fired turbines at our Richland Substation, located in Defiance, Ohio. These units, which will be opera tional later this year, are economical to install. And, unlike large, base-load units, they require shorter construction and start-up time, making it easier to respond to electrical load swings. We expect to add another 765 MW of peak ing capacity over the next three years.
In addition to these improvements, we're using the Internet to further enhance the efficiency of our operations. Participation in auctions of coal and purchases of other goods and services on the Internet are examples of how new technologies are helping us improve our operations and service to customers.
OSHA Safety Rating (Incidents Per 100 Utility Employees) 1.66 2.52 3.91 3.71 --
i
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Succeeding in NEW MARKET S
Our entrance into deregulated electricity markets and continued growth in facilities services and natural gas are just a few ways that we're redefining our Company as the region's premier retail energy and related services supplier.
We are aggressively pursuing new customers in states that have deregu lated their electric utility industries, including Pennsylvania, New Jersey and Delaware, where we are licensed to sell electricity.
Our efforts are paying off.
We're already serving more than 20,000 new electricity accounts, including 800 federal government facilities in New Jersey, such as the Statue of Liberty and Ellis Island; 131 Wal-Mart stores; and 125 Kmart locations.
In 1999, we generated
$60 million in new revenues from unregulated sales outside our traditional electric utility service area, and expect those sales to exceed $300 million in 2000.
We're also expanding our services to customers through innovative partnerships. For instance, we're the exclusive energy services manager for Akron, Ohio-based Republic Technologies International, Inc., the nation's largest producer of high-quality bar steel.
We're managing the electricity and natural gas needs of the company's 16 facilities in the eastern half of the United States.
They are expected to use
$1 billion in energy and related services over the next five years.
Continued growth of our natural gas business is expanding our share of the energy market.
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In 1999, we acquired Atlas Gas Marketing, Inc., near Pittsburgh, Pennsylvania; Volunteer Energy, L.L.C., of Columbus, Ohio; and Belden Energy Services Company of North Canton, Ohio. These three enterprises are now part of our FirstEnergy Trading Services, Inc.,
subsidiary, which acquires and arranges for the delivery of natural gas and electricity to retail customers of our unregu lated affiliates. With the addition of these companies, we serve approximately 50,000 natural gas cus tomers in the Midwest.
We also formed a joint venture - Great Lakes Energy Partners, L.L.C.
with Range Resources Corporation, of Fort Worth, Texas. The venture combined our natural gas properties and pipelines in the Appalachian Basin, located in portions of Ohio, Pennsylvania, West Virginia, Kentucky and Tennessee.
Together, our resources now include:
- Interests in more than 7,700 oil and natural gas wells
- Drilling rights to nearly one million acres
- Proved reserves of 450 billion cubic feet equivalent of natural gas and oil
- 5,000 miles of pipelines Our natural gas business produced approximately
$158 million in revenues in 1999, and sales are expected to more than triple to nearly
$500 million in 2000.
Our Facilities Services Group has emerged as one of the nation's largest providers of mechanical contracting, facilities management, and energy management services. In 1999, the Group generated more than $500 million in revenues, maintaining a pattern of double-digit growth that is expected to continue this year.
Facilities Services is playing a key role in expanding our customer base. Its 11 companies located in Indiana, Maryland, New York, Ohio, Pennsylvania and Virginia - serve a diverse group of national and regional customers, such as Fabri-Centers of America's more than 1,000 Jo-Ann stores and OfficeMax's more than 900 stores throughout the United States.
Such relationships greatly enhance our opportunities for natural gas and electricity sales.
(Far left, clockwise) Our diverse base of customers includes Jacobs Field, homoe of the Cleveland Indians; and the all-electric Prime Outlets at Grove City, north of Pittsburgh, above-ground natural gas transm ission facility; metal fabrication for a mechanical construction customer.
S Retail Kilowatt-Hour Sales (Millions) 60,483 56,545 55,864 55,276
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Pro tec tin E
g the NVI RONM ENT Since passage of the Clean Air Act in 1970, we've spent more than
$4 billion on environmental protection efforts. As a result, we have significantly reduced emissions from our plants. Since 1990 alone, we've cut sulfur dioxide (S02) by more than a third and nitrous oxide (NOx) by more than a half.
We're also developing new markets for recycled materials from our plants.
For instance, by-products from the air-quality control system at our Bruce Mansfield Plant are being used to produce wallboard at a new state of-the-art facility that began operating in 1999 adjacent to the plant.
And, we're scheduled to begin operation later this year of a new petroleum coke-fired boiler at our Bay Shore Power Plant.
The boiler - part of a
$184-million project will improve the plant's performance and reduce fuel costs and emissions by using a by-product from the neighboring British Petroleum's Toledo Refinery as fuel.
The fluidized-bed boiler, the world's largest to be fired by petroleum coke, will generate low-cost steam to make electricity at our plant and petroleum products at the refinery.
Despite the success of our recycling and other environmental protection efforts, the U.S.
Environmental Protection Agency (U.S. EPA) has taken legal action against our 2,233-MW Sammis Plant, along with 43 coal-fired plants owned by other utilities in the Midwest and South, alleging violation of the Clean Air Act.
The U.S. EPA claims that maintenance, repairs and replacements - common industry practices that have been followed for decades under the agency's own oversight - have triggered provisions of the Act that require installation of costly environmental controls, even though capacity and emissions have not increased.
In fact, low-NOx burners, scheduled for installation in 2000, will cut NOx emissions at the plant to less than half of 1990 levels.
New York and Connecticut have taken steps to join the U.S.
EPA's action, alleging that emissions from coal-fired plants in the Midwest and South are to blame for pollution in those states. Scientific evidence does not support their claims.
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($ Millions)
According to the Ozone Transport Assessment Group, formed by U.S.
EPA, the ozone problem in the Northeast would remain essentially unchanged even if all man-made emissions from the Midwest were eliminated.
We are confident that all our plants, including Sammis, are in compliance with the Clean Air Act.
(Right) We've spent a half billion dollars on environmental protection at Sammis; (far left, clockwise) recycled plant materials are being used to produce wallboard; oar Seneca Pumped-Storage Ilydroelectric Generating Station; the new petroleum coke-fired boiler under Construction at our Bco, Shore Plant.
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Retaining and C U S T O Expanding Our M E R BASE in (Above) Our ncwze, Customer Care Web site ojters convenient services; (upper right, clockwxise) a customer service representative at our high-teeh call center, line crew keeping electric service reliable; the Mautnee River in Toledo, Ohio, one of the coninminities
,we servce.
Our work to enhance customer and community service will be a key advantage when Ohio's electricity market opens to competition next year.
The Interactive Voice Response System at our new state-of-the-art customer call center in Akron is helping us respond faster to more customer calls. When severe weather hits, the new technology also enables our crews to restore power more quickly.
In addition, we spent
$30 million to prune and remove trees that interfere with our lines - the primary cause of service interrup tions. We were the only investor-owned electric utility in Ohio to receive the Tree Line USA award from The National Arbor Day Foundation, which honors environmentally sensitive utility tree-care programs.
Reliability was further enhanced with high-tech Ohio 12
systems that provide instantaneous assessments and remote operation of critical distribution system equipment.
We plan to spend
$200 million this year on additional maintenance and system improvements, such as substation upgrades, equipment replacements and distribution system expansions.
We're also using new technology to make it more convenient for customers to do business with us. Our new Customer Care Web site www.firstenergycorp. corn
- enables customers to pay bills, obtain account information, conduct transactions, and learn more about programs we offer.
Our commitment to customers goes beyond providing reliable energy services. We're continuing our tradition of sup porting efforts that make our neighborhoods better places to live and work.
For example, a Girl Scout camp and a Youngstown sports arena are just two of the many organizations in our service area benefiting from our Investment Recovery Facility. Investment Recovery - which has generated $15 million in revenues and avoided costs by selling recycled and reusable equipment and material from our operations - donated refurbished lighting to each organization.
working with vocational agencies to recruit workers with physical or mental challenges.
In addition, we're providing financial support to hundreds of community based educational, civic, health and human services, and cultural organi zations, through the FirstEnergy Foundation. We also offer program support to schools and social service agencies in an effort to help improve the quality of life in the communities we serve. Our corporate philosophy is that community service is good business.
Investment Recovery also supports the diverse needs of our service area by Electric Customers Served 2,185,533 2,166,912 2,159,636 2,141,829
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Board of DIRECTORS Seated - left to rig/ht: Jesse T. dillianms, Sr., Anthont, J..Alexander, H. Peter Burg, Dr. Carol A. Cartwright.
Standing - let to rioht: Robert C. Savage, W'illiam E. Conway, George M. Smart, Russell W. Maiei; Robert B. Heisler, Jr.,
Robert L. Loughhead, Paul J. Powers, Glenn H. Meadows.
H. PETER BURG. 53 Chairman of the Board and Chief Executive Officer of FirstEnergy Corp. Director of FirstEnergy Corp. since 1997 and of Ohio Edison since 1989.
ANTHONY J. ALEXANDER, 48 President of FirstEnergy Corp.
and Director of FirstEnergy Corp. since February 1, 2000.
DR. CAROL A. CARTWRIGHT, 58 President, Kent State University, Kent, Ohio.
Chairperson, Nominating Committee; Member, Finance Committee. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.
WILLIAM F CONWAY, 69 President of William F. Conway
& Associates, Inc., Scottsdale, Arizona. Chairperson, Nuclear Committee; Member, Audit Committee. Director of FirstEnergy Corp. since 1997 and of the former Centerior Energy Corporation from 1994-1997.
ROBERT B. HEISLER, JR., 51 President of Key Capital Partners, Cleveland, Ohio; and Group Executive Vice President of KeyCorp. Member, Compensation and Nominating committees. Director of FirstEnergy Corp. since 1998.
ROBERT L. LOUGHHEAD, 70 Retired, formerly Chairman of the Board, President and Chief Executive Officer of Weirton Steel Corporation, Weirton, West Virginia. Chairperson, Compensation Committee; Member, Audit Committee.
Director of FirstEnergy Corp.
since 1997 and of Ohio Edison from 1980-1997.
RUSSELL W. MAIER, 63 Retired, formerly Chairman of the Board and Chief Executive Officer of Republic Engineered Steels, Inc., Massillon, Ohio.
Member, Compensation and Nuclear committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1995-1997.
GLENN H. MEADOWS, 70 Retired, formerly President and Chief Executive Officer of McNeil Corporation, Akron, Ohio. Chairperson, Audit Committee; Member, Compensation and Nuclear committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1981-1997.
PAUL J. POWERS. 65 Chairman of the Board and Chief Executive Officer of Commercial Intertech Corp.,
Youngstown, Ohio. Chairperson, Finance Committee; Member, Compensation Committee.
Director of FirstEnergy Corp.
since 1997 and of Ohio Edison from 1992-1997.
ROBERT C. SAVAGE, 62 President and Chief Executive Officer of Savage & Associates, Inc., Toledo, Ohio. Member, Finance and Nominating commit tees. Director of FirstEnergy Corp. since 1997 and of the former Centerior Energy Corporation from 1990-1997.
GEORGE M. SMART, 54 Chairman of the Board and President of Phoenix Packaging Corporation, North Canton, Ohio. Member, Audit and Finance committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1988-1997.
JESSE T. WILLIAMS, SR.. 60 Retired, formerly Vice President of Human Resources Policy, Employment Practices and Systems of The Goodyear Tire
& Rubber Company, Akron, Ohio. Member, Audit and Nominating committees.
Director of FirstEnergy Corp.
since 1997 and of Ohio Edison from 1992-1997.
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M a n a g e m e n t CHANGES H. Peter Burg, formerly president and chief executive officer, was elected chairman and chief executive officer.
Anthony J. Alexander, formerly executive vice president and general counsel, was elected president and a member of the Board of Directors.
Arthur R. Garfield, formerly vice president, was elected senior vice president and president of FirstEnergy Services Corp. Leila L. Vespoli, formerly associate general counsel, was elected vice president and general counsel.
Kevin J. Keough, formerly partner at the Cleveland office of McKinsey & Company, was elected vice president. Mark T. Clark, formerly managing director of business development for FirstEnergy Services Corp.,
was elected vice president of the subsidiary. Jeffrey R.
Kalata, formerly group accounting manager for North American Refractories Co., was elected assistant controller.
Robert F. Saunders, formerly vice president, nuclear operations, Susquehanna Nuclear Site, for PP&L, Inc.,
was named president and chief nuclear officer of FirstEnergy Nuclear Operating Company (FENOC).
Lew W. Myers, formerly vice president FENOC Perry, was named senior vice president FENOC Beaver Valley.
FIRSTENERGY CORP.
OFFICERS H. Peter Burg Chairman and Chief Executive Officer Anthony J. Alexander President Arthur R. Garfield Senior Vice President John A. Gill Senior Vice President Richard H. Marsh Vice President and Chief Financial Officer Leila L. Vespoli Vice President and General Counsel Earl T. Carey Vice President Mary Beth Carroll Vice President Kathryn W. Dindo Vice President Douglas S. Elliott Vice President Kevin J. Keough Vice President Guy L. Pipitone Vice President Stanley F. Szwed Vice President Nancy C. Ashcom Corporate Secretary Thomas C. Navin Treasurer Harvey L. Wagner Controller Jeffrey R. Kalata Assistant Controller Randy Scilla Assistant Treasurer Edward J. Udovich Assistant Corporate Secretary NUCLEAR OFFICERS Robert F. Saunders President and Chief Nuclear Officer of FENOC Lew W. Myers Senior Vice President FENOC - Beaver Valley Guy G. Campbell Vice President FENOC-Davis-Besse John K. Wood Vice President FENOC - Perry REGIONAL OFFICERS Lynn M. Cavalier Regional President Eastern Thomas A. Clark Regional President Southern R. Joseph Hrach President Pennsylvania Power Charles E. Jones Regional President Northern Stephen E. Morgan Regional President Central James M. Murray Regional President Western John E. Paganie Regional Vice President Western David W. Whitehead Regional Vice President Northern 15
Manag emen t
REPORT The consolidated financial statements were prepared by the management of FirstEnergy Corp., who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with generally accepted accounting principles and are consistent with other financial information appearing elsewhere in this report. Arthur Andersen LLP, independent public accountants, have expressed an opinion on the Company's consolidated financial statements.
The Company's internal auditors, who are responsible to the Audit Committee of the Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
The Audit Committee consists of five nonemployee directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent public accountants and the internal auditors; recommendation to the Board of Directors of independent accountants to conduct the normal annual audit and special purpose audits as may be required; 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 also reviews the results of management's programs to monitor compliance with the Company's policies on business ethics and risk management. The Audit Committee held six meetings in 1999.
Richard H. Marsh Vice President and Chief Financial Officer Harvey L. Wagner Controller and Chief Accounting Officer rt of INDEPENDENT PUBLIC ACCOUNTANT TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF FIRSTENERGY CORP.:
We have audited the accompanying consolidated bal ance sheets and consolidated statements of capitalization of FirstEnergy Corp. (an Ohio corporation) and sub sidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, common stock holders' equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also S
includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP Cleveland, Ohio February 11, 2000 Repo 16
Selected Financial Data For the Years Ended December 31, FIRSTENERGY CORP.
(In thousands, except per share amounts) 1999 1998 1997 1996 1995 Revenues Income Before Extraordinary Item Net Income Earnings per Share of Common Stock:
Before Extraordinary Item After Extraordinary Item Dividends Declared per Share of Common Stock Total Assets Capitalization at December 31:
Common Stockholders' Equity Preferred Stock:
Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-Term Debt Total Capitalization
$ 6,319,647 568,299 568,299
$ 5,874,906
$ 2,961,125 441,396 305,774 410,874
$2.50
$1.95
$2.50
$1.82
$1.50
$18,224,047
$ 4,563,890 648,395 256,246 6,001,264
$11,469,795
$1.50
$18,192,177
$ 4,449,158 660,195 294,710 6,352,359
$11,756,422 305,774
$2,521,788
$ 302,673
$ 302,673
$2,500,770
$ 294,747
$ 294,747
$1.94
$2.10
$2.05
$1.94
$2.10
$2.05
$1.50
$18,261,481
$ 4,159,598 660,195 334,864 6,969,835
$12,124,492
$1.50
$9,218,623
$2,503,359 211,870 155,000 2,712,760
$5,582,989
$1.50
$9,035,112
$2,407,871 211,870 160,000 2,786,256
$5,565,997 Price Range of Common Stock FirstEnergy Corp.'s Common Stock is listed on the New York Stock Exchange and is traded on other registered exchanges.
First Quarter High-Low Second Quarter High-Low Third Quarter High-Low Fourth Quarter High-Low Yearly High-Low 1999 1998 33-3/16 27-15/16 31-5/8 27-7/8 32-1/8 27-15/16 31-7/8 28-1/2 31-5/16 24-3/4 31-5/16 27-1/16 26-9/16 22-1/8 34-1/16 29-3/16 33-3/16 22-1/8 34-1/16 27-1/16 Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite Transactions.
Holders of Common Stock There were 181,806 and 180,679 holders of the Company's Common Stock of the 232,454,287 shares as of December 31, 1999 and 231,959,541 shares as of January 31, 2000, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 3A.
17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Results of Operations FirstEnergy Corp. was formed when the merger of Ohio Edison Company (OE) and Centerior Energy Corporation (Centerior) became effective on November 8, 1997. The merger was accounted for using purchase accounting under the guidelines of Accounting Principles Board Opinion No.
16, "Business Combinations." Under these guidelines, the results of operations for the combined entity are reported from the point of consummation forward. As a result, our financial statements for 1997 reflect 12 months of operations for OE and its wholly owned subsidiary, Pennsylvania Power Company (Penn), but include only 7 weeks (November 8, to December 31, 1997) for the former Centerior companies - - The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company (TE).
Results for 1998 and 1999 include operations for the entire year for OE and Penn (OE companies), CEI and TE.
During 1998 and 1999, we took additional steps to expand our portfolio of energy-related products and services by completing a number of acquisitions and forming a joint venture. During 1998, FirstEnergy Facilities Services Group, LLC (FE Facilities), a wholly owned subsidiary, acquired eight companies, which mainly provide heating, ventilating and air-conditioning (HVAC) services. FE Facilities made one additional acquisition, in 1999, bringing its total number of acquisitions to 11 over the past three years. On June 8, 1998, we acquired MARBEL Energy Corporation (MARBEL),
a fully integrated natural gas company. On September 30, 1999, MARBEL formed a joint venture with Range Resources Corporation that combines both companies' assets for the development of Appalachian Basin oil and natural gas properties and related gas-gathering and transportation systems. This joint venture is accounted for using the equity method of accounting with our proportionate share of earn ings reflected in our consolidated financial results. During 1999, three additional retail gas acquisitions were added to FirstEnergy Trading Services, Inc. (FETS). All acquisitions in 1998 and 1999 were accounted for using purchase accounting and are included in our consolidated results from their respective acquisition dates.
As Ohio approaches customer choice of energy suppliers in 2001, we continue to develop our unregulated retail sales strategy, in part through acquisitions, which expand the products and services we can offer customers. In addition, related changes to our sales and marketing activities were made during 1999 to further support our retail sales strategy.
As a result, we increased our functional integration across organization lines to improve economies and efficiencies to better serve customers in unregulated markets. By taking advantage of the new markets made available by advancing deregulation, we now cover a 13-state market area in the northeastern portion of the U.S. This expanded market has yielded significant multi-year contracts for us in 1999. We also completed major information systems during 1999, which improve our capabilities while resolving Year 2000 concerns.
Total revenues increased by $445 million in 1999 and
$2.9 billion in 1998 compared to the prior year results. In 1999, the increased revenues resulted primarily from contri butions from the Electric Utility Operating Companies' (EUOC) business segment and newly acquired businesses, which were partially offset by reduced revenues from the FETS business segment due to refocusing its activities to support our retail marketing activities. The EUOC currently represent the more traditional vertically integrated electric utility operations. In 1998, inclusion of a full 12 months of results for the former Centerior companies in the EUOC business segment compared to only 7 weeks in 1997 was the largest factor contributing to the change in electric sales, adding $2.2 billion. The sources of the increases in revenues during 1999 and 1998 are summarized in the following table.
Sources of Revenue Changes 1 9 9 9 1 9 9 8 (In millions)
Electric sales
$213.2
$2,204.7 Other electric utility revenues 3.1 115.0 Total EUOC 216.3 2,319.7 FETS (220.1) 367.6 New businesses acquired 341.5 220.0 Unregulated electric sales 54.0 6.5 Gain on sale of investment 53.0 Net Revenue Increase
$444.7
$2,913.8 18
Electric Sales EUOC revenues increased by $216.3 million in 1999, compared to 1998, benefiting from increased kilowatt-hour sales, offset in part by lower unit prices. Residential, com mercial and industrial customers all contributed to higher EUOC retail sales. Retail kilowatt-hour sales increased due to strong consumer-driven economic growth and, to a lesser extent, the weather. Over 6,500 new EUOC customers were added in 1999. Weather-induced electricity demand in the wholesale market and additional available internal genera tion combined to increase sales to wholesale customers.
EUOC retail kilowatt-hour sales in 1998 increased substantially over 1997 due to the merger with the former Centerior companies. Excluding the impact of the merger, retail sales for the OE companies in 1998 were approximate ly the same as the previous year after setting a new record in 1997. Residential and commercial kilowatt-hour sales bene fited from continued growth in the retail customer base, with over 11,000 new retail customers added in 1998 compared to 1997. The closure of an electric arc furnace by a large steel customer in the latter part of 1997 and a general decline in electricity demand by steel manufacturers due to intense foreign competition contributed to lower industrial sales in 1998, compared to the prior year. Changes in EUOC kilo watt-hour sales by customer class in 1999 and 1998 are summarized in the following table.
EUOC KWH Sales Changes 1999 1 998
- Residential 6.7%
1.7%
Commercial 3.9%
3.5%
Industrial 3.4%
(3.6)%
Total Retail 4.4%
Wholesale 28.4%
8.9%
Total Sales 6.6%
1.4%
- Reflects OE companies only Unregulated kilowatt-hour sales showed strong sales growth in 1999, with sales to commercial customers accounting for most of the increase. Revenues from com mercial customers represented $53.1 million of the $60.5 million of 1999 revenues from unregulated markets. Over 12,000 new unregulated customers were served in 1999.
Several major contracts were entered into in 1999, including one with Republic Technologies International, Inc. (RTI). On August 17, 1999, FirstEnergy Services Corporation (FSC), a wholly owned subsidiary, signed a Master Energy Services and Supply Agreement with RTI. They are expected to use more than $1 billion in energy and related services over the five-year contract period. FSC will manage: the supply and delivery of all of RTI's electricity and natural gas needs; RTI's HVAC requirements; and other energy-related services for RTI. Although unregulated kilowatt-hour sales comprised only 1% of total revenues in 1999, these sales increased substantially compared to 1998 and are expected to be a major source of electric sales growth in future years.
Nonelectric Sales Following an initial expansion of its trading activities in 1998, FETS revenues decreased significantly in 1999, compared to the prior year because of refocusing its activities on supporting our retail marketing activities. Revenues from new business acquisitions increased significantly in both 1999 and 1998 due to acquisitions made by FE Facilities and FETS. In addition, we recognized a gain of $53 million from the sale of a partnership investment in the fourth quarter of 1999, which is reflected in other revenues. This one-time gain was offset by nonrecurring expenses recognized in the fourth quarter of 1999, as further described below.
Operating Expenses Total expenses increased $255.5 million in 1999 compared to 1998 reflecting higher levels of other expenses for EUOC and facilities services activities, as well as additional depreciation and amortization. This increase in other expenses was partially offset by lower fuel and purchased power costs, as well as reduced expenses for FETS. In 1998, total expenses increased $2.4 billion from the previous year primarily due to the inclusion of a full 12 months of expenses for the former Centerior companies, compared to only 7 weeks of expenses in the 1997 results.
Fuel and purchased power costs were $106.7 million lower in 1999, compared to 1998. The EUOC purchased power costs accounted for all of the reduction. Much of the improvement occurred in the second quarter due to the absence of unusual conditions experienced in 1998, which resulted in an additional $77.4 million of purchased power costs. Those costs were incurred during a period of record heat and humidity in late June 1998, which coincided with a regional power shortage resulting in high prices for purchased power. Unscheduled outages at several of our power plants at the same time required the EUOC to purchase significant amounts of power on the spot market. Although above normal temperatures were also experienced in 1999, the EUOC maintained a stronger capacity position compared to the previous year and better met customer demand from their own internal generation. In 1998, fuel and purchased power costs were up $497.5 million compared to 1997. Excluding the merger impact of the Centerior companies in 1998, fuel and purchased power costs for the OE companies increased
$74.4 million for the reasons discussed above.
19
Other expenses for the EUOC rose in 1999 compared to 1998 for several reasons. Refueling outages at Beaver Valley Unit 2 and the Perry Plant, as well as full ownership of those units and Beaver Valley Unit 1 following the Duquesne Light Company (Duquesne) asset swap in early December 1999 and nonrecurring swap-related liabilities assumed, increased our nuclear expenses. The EUOC incurred addi tional costs in 1999 related to improving the availability of their fossil generating units. Also contributing to the increase in other EUOC expenses in 1999 were higher customer, sales and marketing expenses resulting from marketing pro grams and information system costs; higher distribution expenses from storm damage, as well as line and meter maintenance; and a nonrecurring expense related to a change in employee vacation benefits. In 1998, other expenses for the EUOC increased from the previous year principally as a result of the Centerior merger. Excluding the former Centerior companies, 1998 nonnuclear costs decreased from the previous year due primarily to the absence of expenses related to a 1997 voluntary retirement program and estimat ed severance costs which increased other expenses for that year. Lower nonnuclear expenses in 1998 were partially off set by higher nuclear costs at the Beaver Valley Plant.
With FETS activities changing in 1999 to support our retail marketing efforts, other expenses in this business segment decreased significantly from 1998. Also, FETS expenses were significantly lower in 1999 due to the absence of costs incurred in 1998 associated with credit losses and related replacement power costs resulting from the period of sharp price increases in the spot market for electricity in June 1998. The acquisitions in the facility ser vices and natural gas businesses, as well as costs attributable to unregulated sales activity, combined to increase other expenses in both 1999 and 1998 from the previous years.
Accelerated cost recovery in connection with the OE rate reduction plan was the primary factor contributing $160.6 million to the increase in depreciation and amortization in 1999, compared to the prior year. Excluding the effect of the former Centerior companies, depreciation and amortization in 1998 decreased $14.2 million from the prior year mainly due to the net effect of the OE and Penn rate plans.
Interest Expense Interest expense decreased $33.7 million in 1999, from the prior year, because of long-term debt redemptions and refinancings. In 1998, interest expense increased, compared to 1997, due to the inclusion of the former Centerior companies. Excluding the impact of the merger, interest on long-term debt for the OE companies continued to trend downward due to refinancings and redemptions of long term debt.
Extraordinary Item The Pennsylvania Public Utility Commission's (PPUC) authorization of Penn's rate restructuring plan led to the dis continued application of Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation," to Penn's generation business in 1998. This resulted in a write-down of $30.5 million, or
$.13 per common share, of its nuclear generating unit invest ment and the recognition of a portion of such investment -
recoverable through future customer rates - - as a regulatory asset.
Net Income As a result of higher sales revenues, the absence of unusually high purchased power costs experienced in 1998 and lower interest costs, net income increased significantly in 1999 to $568.3 million, compared to $410.9 million in 1998 and $305.8 million in 1997. Basic and diluted earnings per share of common stock were $2.50 in 1999, compared to
$1.82 in 1998 and $1.94 in 1997.
Capital Resources and Liquidity We continue to pursue cost efficiencies to fund strategic investments while also strengthening our financial position.
During 1999, our financing costs continued their downward trend. Net redemptions of long-term debt and preferred stock totaled $528.9 million, including $18.3 million of optional redemptions in 1999. In addition, we completed $359.6 million of refinancings. Combined, these actions are expected to generate annual savings of about $50 million. The average cost of long-term debt was reduced to 7.65% in 1999 from 8.02% at the end of 1997. As of December 31, 1999, our common equity as a percentage of capitalization increased to 40% from 34% at the end of 1997, following the merger with Centerior.
20
We had approximately $111.8 million of cash and temporary investments and $417.8 million of short-term indebtedness on December 31, 1999. Our unused borrowing capability included $136.5 million under revolving lines of credit. At the end of 1999, the EUOC had the capability to issue $2.1 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests and their respective charters, OE, Penn and TE could issue $1.6 billion of preferred stock (assuming no additional debt was issued).
CEI has no restrictions on the issuance of preferred stock.
Our cash requirements in 2000 for operating expenses, construction expenditures, scheduled debt maturities, pre ferred stock redemptions, and common stock repurchases are expected to be met without issuing new securities.
During 1999, we reduced our total debt by approximately
$300.0 million. We have cash requirements of approximately
$2.8 billion for the 2000-2004 period to meet scheduled maturities of long-term debt and sinking fund requirements of preferred stock. Of that amount, approximately $494 mil lion applies to 2000. During 1999, we repurchased and retired 4.6 million shares of our common stock at an average price of $28.08 per share. We have authority to repurchase up to 15 million shares of common stock. We also entered into an equity forward purchase contract, which enables us to purchase an additional 1.4 million shares in November 2000 at an average price of $24.22 per share.
Our capital spending for the period 2000-2004 is expected to be about $3.0 billion (excluding nuclear fuel), of which approximately $650 million applies to 2000. Investments for additional nuclear fuel during the 2000-2004 period are esti mated to be approximately $497 million, of which about
$159 million applies to 2000. During the same period, our nuclear fuel investments are expected to be reduced by approximately $480 million and $106 million, respectively, as the nuclear fuel is consumed. Also, we have operating lease commitments, net of trust cash receipts, of nearly $782 million for the 2000-2004 period, of which approximately
$146 million relates to 2000.
Two transactions were completed in 1999, which modi fied our portfolio of generation resources. On July 26, CEI completed its purchase of the remaining 20 percent interest in the Seneca pumped-storage hydroelectric generation plant from GPU, Inc. for $43 million. The purchase makes avail able 87 megawatts of additional capacity and provides CEI with full ownership of the plant. On December 3, the generating asset transfer with Duquesne was completed.
Duquesne transferred 1,436 megawatts it owned at five generating plants to us in exchange for 1,328 megawatts at three plants owned by our EUOC. The transaction provides us with exclusive ownership and operating control of all generating assets which were formerly jointly owned and operated under the Central Area Power Coordination Group agreement.
Additional generating capacity is under construction, and is expected to go into service in early June 2000 to supply electricity for peak demand periods, reducing our requirements for purchased power. In total, we will be adding 390 megawatts of gas-fired combustion turbines by the end of 2000 to meet this need. Another 150 megawatts of diesel generation will be available to us on a limited basis during the summer of 2000.
We completed four acquisitions during 1999, which further expand energy-related products and services available to our customers. FE Facilities acquired one company having total annual revenues of approximately $14 million.
Collectively, the FE Facilities companies now produce more than $500 million in annual revenues and have approximately 3,400 employees. In addition, FETS acquired three retail gas companies having combined annual revenues of $239 million and more than 43,000 customers. These three acquisitions further expanded our retail natural gas business in Ohio and surrounding states, bringing our total annual revenues in that business to approximately $500 million.
MARBEL and Range Resources Corporation formed a joint venture, Great Lakes Energy Partners L.L.C., on September 30, 1999. This joint venture combined each com pany's Appalachian oil and natural gas properties and related gas gathering and transportation systems with the objective of lowering operating costs, and increasing natural gas mar ket share in the Appalachian Basin. As exclusive marketing agent for the new joint venture, we continue to expand our network of gas assets to supply our retail customer base.
21
Interest Rate Risk Our exposure to fluctuations in market interest rates is mitigated since a significant portion of our debt has fixed interest rates, as noted in the table below. We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 2, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds are recognized by making a corresponding change to the decommissioning liability, as described in Note 1.
Comparison of Carrying Value to Fair Value 2000 2001 2002 2003 2004 Thereafter Total Fair Value (Dollars in millions)
Investments other than Cash and Cash Equivalents:
Fixed Income
$111
$ 60
$ 84
$ 97
$314
$1,370
$2,036
$2,022 Average interest rate 6.5%
7.0%
7.7%
7.7%
7.8%
7.5%
7.5%
Liabilities Long-term Debt:
Fixed rate
$456
$105
$724
$459
$591
$3,009
$5,344
$5,307 Average interest rate 7.1%
8.6%
7.9%
8.0%
7.7%
7.5%
7.6%
Variable rate
$190
$ 847
$1,037
$1,024 Average interest rate 7.5%
4.4%
5.0%
Short-term Borrowings
$418
$ 418
$ 418 Average interest rate 6.5%
6.5%
Preferred Stock
$ 38
$ 85
$ 20
$ 2
$ 2
$ 137
$ 284
$ 280 Average dividend rate 8.9%
8.9%
8.9%
7.5%
7.5%
8.8%
8.8%
Market Risk - Commodity Prices We are exposed to market risk due to fluctuations in elec tricity, natural gas and oil prices. To manage the volatility relating to these exposures, we use a variety of derivative instruments, including forward contracts, options and futures contracts. These derivatives are used principally for hedging purposes and, to a lesser extent, for trading purposes. A sen sitivity analysis has been prepared to estimate our exposure to the market risk of our commodity position. A hypothetical 10 percent adverse shift in quoted market prices in the near term on both our trading and nontrading instruments would not have a material effect on our consolidated financial posi tion, results of operations or cash flows as of or for the year ended December 31, 1999.
Outlook We continue to face many competitive challenges as the electric utility industry undergoes significant changes, including changing regulation and the entrance of more energy suppliers into the marketplace. Retail wheeling, which began in 1999 in our Pennsylvania service area, allows retail customers to purchase electricity from alterna tive energy suppliers. Recent legislation provides for similar changes beginning in 2001 in Ohio. Our existing regulatory plans provide us with a solid foundation to position us to meet the challenges we are facing by significantly reducing fixed costs and lowering rates to a more competitive level.
The transition plan ultimately approved by the Public Utilities Commission of Ohio (PUCO) will supersede our current Ohio rate plans.
OE's Rate Reduction and Economic Development Plan, approved by the PUCO in 1995, and FirstEnergy's Rate Reduction and Economic Development Plan for CEI and TE, approved in January 1997, provide interim rate credits to customers during the periods covered by the plans. The OE regulatory plan provides for accelerated capital recovery.
The regulatory plan for CEI and TE includes a commitment to accelerate depreciation on the regulatory books. The CEI/TE plan does not provide for full recovery of nuclear operations; accordingly, CEI and TE ceased application of SFAS 71 for their nuclear operations when implementation of the FirstEnergy regulatory plan became probable.
22
In July 1999, Ohio's new electric utility restructuring leg islation, which will allow Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the new law provides for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005. The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application.
On behalf of our Ohio electric utility operating compa nies - - OE, CEI and TE - - we refiled our transition plan on December 22, 1999. The plan was originally filed with the PUCO on October 4, 1999, but was refiled to conform to PUCO rules established on November 30, 1999. The new filing also included additional information on our plans to turn over control, and perhaps ownership, of our transmis sion assets to the Alliance Regional Transmission Organization (Alliance), which is discussed below.
The transition plan itemizes, or unbundles, the current price of electricity into separate components - including generation, transmission, distribution and transition charges.
As required by the PUCO's rules, our filing also included our proposals on corporate separation of our regulated and unregulated operations, operational and technical support changes needed to accommodate customer choice, an educa tion program to inform customers of their options under the law, and how our transmission system will be operated to ensure access to all users. Under the plan, customers who remain with OE, CEI, or TE as their generation provider will continue to receive savings under our rate plans, expected to total $759 million between 2000 and 2005. In addition, cus tomers will save $358 million through reduced charges for taxes and a 5% reduction in the price of generation for resi dential customers beginning January 1, 2001. Customer prices are expected to be frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including the 5% reduction in the price of generation for residential customers. The plan proposes recovery of generation-related transition costs of approxi mately $4.5 billion ($4.0 billion, net of deferred income taxes) over the market development period; transition costs related to regulatory assets aggregating approximately
$4.2 billion ($2.9 billion, net of deferred income taxes) are expected to be recovered over the period of 2001 through early 2004 for OE; 2001 through 2007 for TE; and 2001 through 2010 for CER.
When the transition plan is approved by the PUCO, the application of SFAS 71 to OE's generation business and the nonnuclear generation businesses of CEI and TE will be discontinued. In the meantime, we will continue to bill and collect cost-based rates relating to CEI's and TE's nonnuclear operations and all of OE's operations through the end of 2000. If the transition plans ultimately approved by the PUCO for OE, CEI and TE do not provide adequate recovery of their nuclear generating unit investments and regulatory assets, there would be a charge to earnings which could have a material adverse effect on our results of operations and financial condition and those of our Ohio EUOC. The EUOC believe they will continue to bill and collect cost-based rates for their transmission and distribu tion services, which will remain regulated; accordingly, it is appropriate that the EUOC continue the application of SFAS 71 to those operations after December 31, 2000.
For Penn, application of SFAS 71 was discontinued for the generation portion of its business in 1998 following PPUC approval of its restructuring plan. Under the plan, a phase-in period for customer choice began with 66% of Penn's customers able to select their energy supplier begin ning January 2, 1999, and all remaining customers able to select their energy providers starting January 1, 2001. Penn is entitled to recover $236 million of stranded costs through a competitive transition charge that started in 1999 and ends in 2006.
In the second half of 1999, we received notification of pending legal actions based on alleged violations of the Clean Air Act at our W. H. Sammis Plant involving the states of New York and Connecticut as well as the U.S.
Department of Justice. The civil complaint filed by the U.S.
Department of Justice requests installation of "best available control technology" as well as civil penalties of up to
$27,500 per day. We believe the Sammis Plant is in full compliance with the Clean Air Act and the legal actions are without merit. However, we are unable to predict the outcome of this litigation. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. We expect the Sammis Plant to continue to operate while the matter is being decided.
23
CEI and TE have been named as "potentially responsible parties" (PRPs) for three sites listed on the Superfund National Priorities List and are aware of their potential involvement in the cleanup of several other sites. Allegations that CEI and TE disposed of hazardous waste at these sites, and the amount involved are often unsubstantiated and sub ject to dispute. Federal law provides that all PRPs for a par ticular site be held liable on a joint and several basis. If CEI and TE were held liable for 100% of the cleanup costs of all sites, the ultimate liability could be as high as $340 million.
However, we believe that the actual cleanup costs will be substantially lower than $340 million, that CEI's and TE's share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. CEI and TE have accrued liabilities of
$5.4 million as of December 31, 1999, based on estimates of the costs of cleanup and their proportionate responsibility for such costs. CEI and TE believe that the waste disposal costs will not have a material adverse effect on their finan cial condition, cash flows or results of operations.
On October 27, 1999, the Federal Energy Regulatory Commission (FERC) approved our plan to transfer our transmission assets to American Transmission Systems Inc.
(ATSI), a wholly owned subsidiary. The PUCO approved the transfer in February 2000. PPUC and Securities and Exchange Commission regulatory approvals are also required. The new subsidiary represents a first step toward the goal of establishing or becoming part of a larger inde pendent, regional transmission organization (RTO). We believe that such an entity better addresses the FERC's stated transmission objectives of non-discriminatory service, while providing for streamlined and cost-effective operation. In working toward that goal, we joined with four other companies American Electric Power, Consumers Energy, Detroit Edison and Virginia Power -
to form the Alliance RTO.
On June 3, 1999, the Alliance submitted an application to the FERC to form an independent, for profit RTO. On December 15, 1999, the FERC issued an order conditionally approving the Alliance's application.
Recently Issued Accounting Standard In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value.
SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualify ing hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement.
We have not completed quantifying the impacts of adopting SFAS 133 on our financial statements or determined the method of its adoption. However, SFAS 133 could increase volatility in earnings and other comprehensive income. We anticipate adopting the new statement on its amended effec tive date of January 1, 2001.
Year 2000 Update Based on the results of our remediation and testing efforts, we filed documents with the North American Electric Reliability Council, Nuclear Regulatory Commission, PUCO and PPUC that as of June 30, 1999, our generation, transmission, and distribution systems were ready to serve customers in the year 2000. We have since experienced no failures or interruptions of service to our customers resulting from the Year 2000 issue, which was consistent with our expectations. We spent $84.9 million on Year 2000-related costs through December 31, 1999, which was slightly lower than previously estimated. Of this total,
$68.3 million was capitalized since those costs are attributable to the purchase of new software for total system replacements because the Year 2000 solution comprises only a portion of the benefits resulting from the system replacements. The remaining $16.6 million was expensed as incurred. We do not believe there are any continuing Year 2000 issues to be addressed, nor any additional material Year 2000 expenditures.
Forward-Looking Information This discussion includes forward-looking statements based on information currently available to management that 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 market prices, legislative and regulatory changes, and the availability and cost of capital and other similar factors.
24
Consolidated Statements of Income F I RST ENERGY C ORP.
(In thousands, except per share amounts)
For the Years Ended December 31, REVENUES:
Electric sales Other-electric utilities Facilities services Trading services Other Total revenues EXPENSES:
Fuel and purchased power Other expenses:
Electric utilities Facilities services Trading services Other Provision for depreciation and amortization General taxes Total expenses INCOME BEFORE INTEREST AND INCOME TAXES NET INTEREST CHARGES:
Interest expense Allowance for borrowed funds used during construction and capitalized interest Subsidiaries' preferred stock dividends Net interest charges INCOME TAXES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY ITEM (NET OF INCOME TAX BENEFIT OF
$21,208,000) (Note 1)
NET INCOME WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING BASIC AND DILUTED EARNINGS PER SHARE OF COMMON STOCK (Note 3C):
Income before extraordinary item Extraordinary item (Net of income taxes) (Note 1)
Net income DIVIDENDS DECLARED PER SHARE OF COMMON STOCK 1999
$5,192,876 260,887 502,990 190,634 172,260 6,319,647 876,986 1,632,638 469,176 196,474 126,926 937,976 544,052 4,784,228 1,535,419 509,169 (13,355) 76,479 572,293 394,827 568,299 1998
$4,979,718 257,750 198,336 410,728 28,374 5,874,906 983,735 1,492,461 184,440 517,001 41,337 758,865 550,908 4,528,747 1,346,159 542,819 (7,642) 65,799 600,976 303,787 441,396 1997
$2,774,996 142,742 43,145 242 2,961,125 486,267 851,146 44,032 474,679 282,163 2,138,287 822,838 284,180 (3,469) 27,818 308,529 208,535 305,774 (30,522)
$ 568,299
$ 410,874
$ 305,774 227,227
$2.50
$2.50
$1.50 226,373 157,464
$1.95
$1.94
(.13)
$1.82
$1.94
$1.50
$1.50 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
25
Consolidated Balance Sheets At December 31, ASSETS CURRENT ASSETS:
Cash and cash equivalents Receivables Customers (less accumulated provisions of $6,719,000 and $6,397,000, respectively, for uncollectible accounts)
Other (less accumulated provisions of $5,359,000 and $46,251,000, respectively, for uncollectible accounts)
Materials and supplies, at average cost Owned Under consignment Prepayments and other PROPERTY, PLANT AND EQUIPMENT:
In service Less-Accumulated provision for depreciation Construction work in progress INVESTMENTS:
Capital trust investments (Note 2)
Letter of credit collateralization (Note 2)
Nuclear plant decommissioning trusts Other DEFERRED CHARGES:
Regulatory assets Goodwill Other LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock Short-term borrowings (Note 4)
Accounts payable Accrued taxes Accrued interest Other CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders' equity Preferred stock of consolidated subsidiaries Not subject to mandatory redemption Subject to mandatory redemption Ohio Edison obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Ohio Edison subordinated debentures Long-term debt DEFERRED CREDITS:
Accumulated deferred income taxes Accumulated deferred investment tax credits Other postretirement benefits Nuclear plant decommissioning costs Other COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)
FIRSTENERGY CORP.
(In thousands) 1999 1998 111,788 322,687 445,242 154,834 99,231 167,894 1,301,676 14,645,131 5,919,170 8,725,961 367-180 9,093,341 1,281,834 277,763 543,694 599,443 2,702,734 2,543,427 2,129,902 452,967 5,126,296
$18,224,047 762,520 417,819 360,379 409,724 125,397 301,572 2-377-411 4,563,890 648,395 136,246 120,000 6,001,264 11,469,795 2,231,265 269,083 498,184 562,295 816,014 4,376,841
$18,224,047 The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
77,798 239,183 322,186 145,926 110,109 171,931 1,067,133 14,961,664 6,012,761 8,948,903 293,671 9,242,574 1,329,010 277,763 358,371 391,855 2,356,999 2,887,437 2,167,968 470,066 5,525,471
$18,192,177 876,470 254,470 247,353 401,688 141,575 255,158 2,176,714 4,449,158 660,195 174,710 120,000 6,352,359 11,756,422 2,282,864 286,154 463,642 375,958 850,423 4,259,041
$18,192,177 26 I
I
- I -
2-*77.411
Consolidated Statements of Capitalization FIRSTENERGY CORP.
(Dollars in thousands, except per share amounts) 1999 At December 3 1, COMMON STOCKHOLDERS' EQUITY:
Common stock, $.10 par value-authorized 300,000,000 shares 232,454,287 and 237,069,087 shares outstanding, respectively Other paid-in capital Accumulated other comprehensive income (Note 3D)
Retained earnings (Note 3A)
Unallocated employee stock ownership plan common stock 6,778,905 and 7,406,332 shares, respectively (Note 3B)
Total common stockholders' equity PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Note 3E):
Cumulative, $100 par value Authorized 6,000,000 shares Not Subject to Mandatory Redemption:
3.90%
4.40%
4.44%
4.56%
Cumulative, $25 par value Authorized 8,000,000 shares Not Subject to Mandatory Redemption:
7.75%
Total Not Subject to Mandatory Redemption Cumulative, $100 par value Subject to Mandatory Redemption (Note 3F):
8.45%
Redemption Within One Year Pennsylvania Power Company Cumulative, $100 par value Authorized 1,200,000 shares Not Subject to Mandatory Redemption:
4.24%
4.25%
4.64%
7.64%
7.75%
8.00%
Total Not Subject to Mandatory Redemption Subject to Mandatory Redemption (Note 3F):
7.625%
OE OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY OE SUBORDINATED DEBENTURES (Note 3G):
Cumulative, $25 par value Authorized 4,800,000 shares Subject to Mandatory Redemption:
9.00%
Number of Shares Outstanding 1999 1998 152,510 176,280 136,560 144,300 609,650 152,510 176,280 136,560 144,300 609,650 4,000,000 4,000,000 4,609,650 4,609,650 100,000 150,000 100,000 150,000 40,000 41,049 60,000 250,000 40,000 41,049 60,000 60,000 250,000 58,000 391,049 509,049 150,000 150,000 4,800,000 4,800,000 Optional Redemption Price Per Share Aggregate
$103.63 108.00 103.50 103.38
$ 15,804 19,038 14,134 14,917 63,893 23,245 3,722,375 (195) 945,241 (126,776)
I I
4,563,890 4,449,158 15,251 17,628 13,656 14,430 60,965 25.00 100,000 100,000 103.13 105.00 102.98
$163,8931 160,965 160,965 4,125 4,310 6,179 10,000 (5,000) 5,000 4,000 4,105 6,000 25,000
$ 14,6141 39,105 50,905 106.10
$ 15,9151 15,000 15,000 120,000 1
120,000 1998 23,707 3,846,513 (439) 718,409 (139,032) 15,251 17,628 13,656 14,430 60,965 100,000 15,000 (5,000) 10,000 4,000 4,105 6,000 6,000 25,000 5,800 27
Consolidated Statements of Capitalization (Cont'd)
FIRSTENERGY CORP.
(Dollars in thousands, except per share amounts)
At December 31, PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Cont'd)
Cleveland Electric Illuminating Company Cumulative, without par value Authorized 4,000,000 shares Not Subject to Mandatory Redemption:
$ 7.40 Series A
$ 7.56 Series B Adjustable Series L
$42.40 Series T Total Not Subject to Mandatory Redemption Subject to Mandatory Redemption
$ 7.35 Series C
$88.00 Series E
$91.50 Series Q
$88.00 Series R
$90.00 Series S Number of Shares Outstanding 1999 1998 500,000 450,000 474,000 200,000 500,000 450,000 474,000 200,000 1,624,000 1,624,000 90,000 3,000 21,430 50,000 55.250 219,680 Redemption Within One Year Total Subject to Mandatory Redemption 219,680 Toledo Edison Company Cumulative, $100 Par Value Authorized 3,000,000 shares Not Subject to Mandatory Redemption:
$ 4.25
$ 4.56
$ 4.25
$ 8.32
$ 7.76
$ 7.80
$10.00 Cumulative, $25 Par Value Authorized 12,000,000 shares Not Subject to Mandatory Redemption:
$2.21
$2.365 Adjustable Series A Adjustable Series B Total Not Subject to Mandatory Redemption Cumulative, $100 par value Subject to Mandatory Redemption:
$9.375 Redemption Within One Year Total Subject to Mandatory Redemption 160,000 50,000 100,000 100,000 150,000 150,000 190,000 900,000 1,000,000 1,400,000 1,200,000 1,200,000 4,800,000 100,000 6,000 32,144 50,000 74,000 262,144 262,144 160,000 50,000 100,000 100,000 150,000 150,000 190,000 900,000 1,000,000 1,400,000 1,200,000 1,200,000 4,800,000 5,700,000 5,700,000 16,900
-~16,900 1999 1998 Optional Redemption Price Per Share Aggregate
$ 101.00 102.26 100.00 500.00 101.00 1,000.00 1,000.00 104.63 101.00 102.00 102.46 102.44 101.65 101.00 25.25 27.75 25.00 25.00
$ 50,500 46,017 47,400 100,000
$ 50,000 45,071 46,404 96,850
$ 50,000 45,071 46,404 96,850
$243,917 238,325 238,325 9,090 3,000 21,430 33,520
$ 33,520
$ 16,740 5,050 10,200 10,246 15,366 15,248 19,190 92,040 25,250 38,850 30,000 30,000 124,100 9,110 3,000 21,430 55,000 61,170 149,710 (33,464) 116,246 16,000 5,000 10,000 10,000 15,000 15,000 19,000 "90,000 25,000 35,000 30,000 30,000 120,000 10,110 6,000 32,144 55,000 79,920 183,174 (33,464) 149,710 16,000 5,000 10,000 10,000 15,000 15,000 19,000 90,000 25,000 35,000 30,000 30,000 120,000
$216,140 210,000 210,000 1,690 (1,690) 28
F1IRSTE NJ,'L GY C ORP.
Consolidated Statements of Capitalization (Cont'd)
LONG-TERM DEBT (Note 3H) (Interest rates reflect weighted average rates)
At December 31, Ohio Edison Co.
Due 1999-2004 Due 2005-2009 Due 2010-2014 Due 2015-2019 Due 2020-2024 Due 2025-2029 Due 2030-2034 Total-Ohio Edison Cleveland Electric Illuminating Co.
Due 1999-2004 Due 2005-2009 Due 2010-2014 Due 2015-2019 Due 2020-2024 Due 2025-2029 Due 2030-2034 Total-Cleveland Electric Toledo Edison Co.
Due 1999-2004 Due 2005-2009 Due 2010-2014 Due 2015-2019 Due 2020-2024 Due 2025-2029 Due 2030-2034 Total-Toledo Edison Pennsylvania Power Co.
Due 1999-2004 Due 2005-2009 Due 2010-2014 Due 2015-2019 Due 2020-2024 Due 2025-2029 Due 2030-2034 Total-Penn Power OES Fuel Bay Shore Power MARBEL Energy Corp.
Facilities Services Group Total Capital lease obligations Net unamortized premium on debt Long-term debt due within one year Total long-term debt TOTAL CAPITALIZATION FIRST MORTGAGE BONDS SECURED NOTES 1999 1998 1999 19 7.81%
6.88%
7.99%
7.54%
8.72%
9.00%
7.90%
7.19%
9.74%
9.74%
9.74%
8.33%
$ 509,265 80,000 219,460 808,725 295,000 425,000 150,000 870,000 179,925 179,925 79,370 4,870 4,870 4,903 33,750 127,763
$1,986,413
$ 659,265 80,000 225,960 965,225 295,000 425,000 150,000 870,000 265,325 265,325 79,857 4,870 4,870 4,903 33,750 128,250
$2,228,800 7.57%
7.65%
6.89%
7.02%
5.75%
5.45%
7.64%
7.29%
8.00%
6.74%
6.66%
7.59%
4.56%
7.84%
7.13%
4.98%
8.00%
7.89%
5.90%
6.45%
5.40%
6.28%
6.68%
6.03%
6.85%
6.72%
6.40%
6.61%
$ 269,152 49,534 66,000 129,942 119,734 14,800 649,162 559,650 271,700 78,700 412,630 264,160 148,843 104,895 1,840,578 266,000 30,000 67,300 210,600 13,851 587,751 28,200 1,000 45,325 27,182 47,972 149,679 81,260 147,500 14,782
$3,470,712 98
$ 203,062 48,194 113,725 317,943 119,734 14,800 817,458 704,180 271,700 78,700 412,630 291,860 148,843 104,895 2,012,808 284,500 30,000 31,250 67,300 266,700 13,851 693,601 23,000 1,000 45,325 32,382 47,972 149,679 79,524 147,500 12,418 10,237
$3,923,225 UNSECURED NOTES F1999 1 199-8 5.40%
5.58%
7.28%
10.00%
10.00%
5.90%
8.00%
7.29%
$ 742,225 742,225 27,700 27,700 226,100 150 700 226,950 5,200 5,200 692 1,887
$1,004,654
$566,500 566,500 138,750 150 700 139,600 3,917
$710,017 TOTAL 1999 1998
$ 2,200,112 $ 2,349,183 2,738,278 2,882,808 994,626 1,098,526 282,642 81,260 147,500 692 16,669 6,461,779 277,929 79,524 147,500 12,418 14,154 6,862,042 158,303 199,491 105,238 (724,056) 6,001,264 127,142 (836,316) 6,352,359
$11,469,795 $11,756,422 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
29 (In thousands)
Consolidated Statements of Common Stockholders' Equity FIRSTENERGY CORP.
(Dollars in thousands)
Balance, January 1, 1997 Net income Minimum liability for unfunded retirement benefits, net of
$26,000 of income taxes Comprehensive income Centerior acquisition Allocation of ESOP shares Cash dividends on common stock Balance, December 31, 1997 Net income Minimum liability for unfunded retirement benefits, net of
$53,000 of income taxes Comprehensive income Business acquisitions Allocation of ESOP shares Cash dividends on common stock Balance, December 31, 1998 Net income Minimum liability for unfunded retirement benefits, net of
$160,000 of income taxes Comprehensive income Reacquired common stock Centerior acquisition adjustment Allocation of ESOP shares Cash dividends on common stock Balance, December 31, 1999 Comprehensive Income Note 3D
$305,774 45
$305,819
$410,874 175
$411,049 Number of Shares 152,569,437 77,637,704 Par Value
$1,373,125 (1,350,104) 230,207,141 23,021 6,861,946 237,069,087
$568,299 244
$568,543 (4,614,800) 232,454,287 686 23,707 (462)
$ 23,245 Other Paid-In Capital
$ 728,261 2,907,387 1,874 3,637,522 203,496 5,495 3,846,513 (129.671)I Accumulated Other Comprehensive Income Note 3D
$(659) 45 (614) 175 (439) 244 (468) 6,001
$3,722,375
$(195)
Retained Earnings
$ 557,642 305,774 (216,770) 646,646 410,874 (339,111) 718,409 568,299 Unallocated ESOP Common Stock
$(155,010) 8,033 (146,977) 7,945 (139,032) 12,256 (341,467)
$ 945,241
$(126,776)
Consolidated Statements of Preferred Stock (Dollars in thousands)
Balance, January 1, 1997 Centerior acquisition Redemptions 8.45% Series Balance, December 31, 1997 Redemptions 8.45% Series
$ 7.35 Series C
$88.00 Series E
$91.50 Series Q
$9.375 Series Balance, December 31, 1998 Redemptions 7.64% Series 8.00% Series 8.45% Series
$7.35 Series C
$88.00 Series E
$91.50 Series Q
$90.00 Series S
$9.375 Series Balance, December 31, 1999 Not Subject to Mandatory Redemption Par or Number Stated of Shares Value 5,118,699
$211,870 7,324,000 448,325 12,442,699 660,195 12,442,699 (60,000)
(58,000) 12,324,699 660,195 (6,000)
(5,800)
$648,395 Subject to Mandatory Redemption Par or Number Stated of Shares Value 5,200,000
$160,000 319,408 201,243 (50,000)
(5,000) 5,469,408 356,243 (50,000)
(10,000)
(3,000)
(10,714)
(16,650) 5,379,044 (50,000)
(10,000)
(3,000)
(10,714)
(18,750)
(16,900) 5,269,680 (5,000)
(1,000)
(3,000)
(10,714)
(1,665) 334,864 (5,000)
(1,000)
(3,000)
(10,714)
(18,750)
(1,690)
$294,710 30 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP.
(In thousands)
Consolidated Statements of Cash Flows For the Years Ended December 31, 1999 CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income Adjustments to reconcile net income to net cash from operating activities:
Provision for depreciation and amortization Nuclear fuel and lease amortization Other amortization, net Deferred income taxes, net Investment tax credits, net Allowance for equity funds used during construction Extraordinary item Receivables Materials and supplies Accounts payable Other Net cash provided from operating activities CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing Common stock Long-term debt Ohio Schools Council prepayment program Short-term borrowings, net Redemptions and Repayments Common stock Preferred stock Long-term debt Short-term borrowings, net Common Stock Dividend Payments Net cash provided from (used for) financing activities CASH FLOWS FROM INVESTING ACTIVITIES:
Centerior acquisition Property additions Cash investments Other Net cash used for investing activities Net increase (decrease) in cash and cash equivalents Cash and cash ecuivalents at bezinninR of period*
Cash and cash equivalents at end of year SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year Interest (net of amounts capitalized)
Income taxes
$ 568,299 937,976 104,928 (10,730)
(45,054)
(19,661)
(203,567) 19,631 82,578 53,906 1,488,306 364,832 163,327 130,133 52,159 847,006 341,467 (842,606) 624,901 (41,213) 28,022 611,710 33,990 77,798
$ 111,788
$ 410,874 758,865 94,348 (13,007)
(23,763)
(22,070) 51,730 35,515 (14,235)
(73,205)
(49,727) 1,155,325 204,182 499,975 116,598 21,379 804,780 48,354 339,111 (392,869) 652,852 47,804 82,239 782,895 (20,439) 98,237 77,798
$ 305,774 474,679 61,960 (1,187)
(29,093)
(16,252)
(201) 21,846 (18,909) 57,087 733 856,437 1,558,237 89,773 5,000 335,909 47,251 237,848 1,022,002 1,582,459 203,839 8,934 62,237 1,857,469 20,970 77,267 98,237
$ 520,072
$ 536,064
$ 281,670
$ 441,067
$ 326,268
$ 265,615
"*1997 beginning balance includes Centerior cash and cash equivalents as of the November 8, 1997 acquisition date.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
31 1998 1997
FIRSTENERGY CORP.
(In thousands)
Consolidated Statements of Taxes For the Years Ended December 31, GENERAL TAXES:
Real and personal property State gross receipts Social security and unemployment Other Total general taxes PROVISION FOR INCOME TAXES:
Currently payable Federal State Deferred, net Federal State Investment tax credit amortization Total provision for income taxes RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes Federal income tax expense at statutory rate Increases (reductions) in taxes resulting from Amortization of investment tax credits State income taxes, net of federal income tax benefit Amortization of tax regulatory assets Amortization of goodwill Preferred stock dividends Other, net Total provision for income taxes ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences Deferred nuclear expense Customer receivables for future income taxes Competitive transition charge Deferred sale and leaseback costs Unamortized investment tax credits Unused alternative minimum tax credits Other Net deferred income tax liability 1999 1998 1997
$ 276,227 220,117 37,019 10,689
$ 544,052
$ 433,872 25,670 459,542 (36,021)
(9,033)
(45,054)
(19,661)
$ 394,827
$ 292,503 217,633 27,363 13,409
$ 550,908
$ 313,960 14,452 328,412 (14,259)
(9,504)
(23,763)
(22,070)
$ 282,579
$ 137,816 118,390 16,551 9,406
$ 282,163
$ 235,728 18,152 253,880 (23,204)
(5,889)
(29,093)
(16,252)
$ 208,535
$ 963,126
$ 693,453
$ 514,309
$ 337,094
$ 242,709
$ 180,008 (19,661) 10,814 23,908 19,341 22,988 343
$ 394,827
$1,878,904 421,837 159,577 115,277 (129,775)
(96,036)
(101,185)
(17,334)
$2,231,265 (22,070) 3,216 28,915 17,868 19,250 (7,309)
$ 282,579
$1,938,735 436,601 159,526 135,730 (61,506)
(102,085)
(190,781)
(33,356)
$2,282,864 (16,252) 7,971 30,735 2,685 5,956 (2,568)
$ 208,535
$2,091,207 454,902 262,428 (121,974)
(116,593)
(243,039)
(22,626)
$2,304,305 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
32
NOTES TO CONSOLIDATED FINANCIAL ST
- 1. Summary of Significant Accounting Policies:
The consolidated financial statements include FirstEnergy Corp. (Company) and its principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE).
The Company and its utility subsidiaries are referred to throughout as "Companies." The Company's 1997 results of operations include the results of CEI and TE for the period November 8, 1997 through December 31, 1997. The consol idated financial statements also include the Company's other principal subsidiaries: FirstEnergy Facilities Services Group, LLC. (FE Facilities); FirstEnergy Trading Services, Inc.
(FETS); and MARBEL Energy Corporation (MARBEL). FE Facilities is the parent company of several heating, ventilat ing, air conditioning and energy management companies.
FETS markets and trades electricity and natural gas in unregulated markets. MARBEL is a fully integrated natural gas company. Significant intercompany transactions have been eliminated. The Companies follow the accounting poli cies and practices prescribed by the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of finan cial statements in conformity with generally accepted accounting principles requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain prior year amounts have been reclassified to conform with the current year presentation.
Revenues -
The Companies' principal business is providing electric service to customers in central and north ern Ohio and western Pennsylvania. The Companies' retail customers are metered on a cycle basis. Revenue is recog nized for unbilled electric service through the end of the year.
Receivables from customers include sales to residential, commercial and industrial customers located in the Companies' service area and sales to wholesale customers.
There was no material concentration of receivables at December 31, 1999 or 1998, with respect to any particular segment of the Companies' customers.
CEI and TE sell substantially all of their retail customer accounts receivable to Centerior Funding Corp. under an asset-backed securitization agreement which expires in 2001. Centerior Funding completed a public sale of $150 million of receivables-backed investor certificates in 1996 in a transaction that qualified for sale accounting treatment.
Regulatory Plans -
The PUCO approved OE's Rate Reduction and Economic Development Plan in 1995 and FirstEnergy's Rate Reduction and Economic Development Plan for CEI and TE in January 1997. These regulatory plans were to maintain current base electric rates for OE, CEI and TE through December 31, 2005. At the end of the regulatory plan periods, OE base rates were to be reduced by $300 million (approximately 20 percent below current levels) and CEI and TE base rates were to be reduced by a combined $310 million (approximately 15 percent below current levels). The plans also revised the Companies' fuel cost recovery methods. The Companies formerly recovered fuel-related costs not otherwise included in base rates from retail customers through separate energy rates. In accordance with the respective regulatory plans, OE's, CEI's and TE's fuel rates would be frozen through the regulatory plan period, subject to limited periodic adjust ments. As part of OE's and FirstEnergy's regulatory plans, transition rate credits were implemented for customers, which are expected to reduce operating revenues for OE by approximately $600 million and CEI and TE by approxi mately $391 million during the regulatory plan period.
In July 1999, Ohio's new electric utility restructuring legislation which will allow Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the new law pro vides for a five percent reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005. The period for the recov ery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application.
33 AT EM ENT S
The Company, on behalf of its Ohio electric utility oper ating companies - - OE, CEI and TE - - on December 22, 1999 refiled its transition plan under Ohio's new electric utility restructuring law. The plan was originally filed with the PUCO on October 4, 1999, but was refiled to conform to PUCO rules established on November 30, 1999. The new filing also included additional information on FirstEnergy's plans to turn over control, and perhaps ownership, of its transmission assets to the Alliance Regional Transmission Organization. The PUCO indicated that it will endeavor to issue its order in the Company's case within 275 days of the initial October filing date.
The transition plan itemizes, or unbundles, the current price of electricity into its component elements - including generation, transmission, distribution and transition charges.
As required by the PUCO's rules, the Company's filing also included its proposals on corporate separation of its regulat ed and unregulated operations, operational and technical support changes needed to accommodate customer choice, an education program to inform customers of their options under the new law, and how the Company's transmission system will be operated to ensure access to all users.
Under the plan, customers who remain with OE, CEI, or TE as their generation provider will continue to receive savings under the Company's rate plans, expected to total
$759 million between 2000 and 2005. In addition, customers will save $358 million through reduced charges for taxes and a five percent reduction in the price of generation for residential customers beginning January 1, 2001. Customer prices are expected to be frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including the five percent reduction in the price of generation for residential customers. The plan proposes recovery of generation-related transition costs of approximately $4.5 billion ($4.0 billion, net of deferred income taxes) over the market development period; transi tion costs related to regulatory assets aggregating approxi mately $4.2 billion ($2.9 billion, net of deferred income taxes) will be recovered over the period of 2001 through early 2004 for OE; 2001 through 2007 for TE; and 2001 through 2010 for CEI.
In June 1998, the PPUC authorized a rate restructuring plan for Penn which essentially resulted in the deregulation of Penn's generation business as of June 30, 1998. Penn was required to remove from its balance sheet all regulatory assets and liabilities related to its generation business and assess all other assets for impairment. The Securities and Exchange Commission (SEC) issued interpretive guidance regarding asset impairment measurement which concluded that any supplemental regulated cash flows such as a com petitive transition charge (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, Penn reduced its nuclear generating unit investments by approximately $305 million, of which approximately $227 million was recognized as a regulatory asset to be recovered through a CTC over a seven-year transition period; the remaining net amount of
$78 million was written off. The charge of $51.7 million
($30.5 million after income taxes) for discontinuing the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), to Penn's generation business was recorded as a 1998 extraordinary item on the Consolidated Statement of Income.
All of the Companies' regulatory assets are being recov ered under provisions of the regulatory plans. In addition, the PUCO has authorized OE to recognize additional capital recovery related to its generating assets (which is reflected as additional depreciation expense) and additional amortiza tion of regulatory assets during the regulatory plan period of at least $2 billion, and the PPUC had authorized Penn to accelerate at least $358 million, more than the amounts that would have been recognized if the regulatory plans were not in effect. These additional amounts are being recovered through current rates. As of December 31, 1999, OE's and Penn's cumulative additional capital recovery and regulatory asset amortization amounted to $1.048 billion (including Penn's impairment discussed above and CTC recovery). CEI and TE recognized a fair value purchase accounting adjust ment of $2.55 billion in connection with the FirstEnergy 34
merger; that fair value adjustment recognized for financial reporting purposes will ultimately satisfy the $2 billion asset reduction commitment contained in the CEI and TE regula tory plan. For regulatory purposes, CEI and TE will recog nize the accelerated amortization over the period that their rate plan is in effect.
Application of SFAS 71 was discontinued in 1997 with respect to CEI's and TE's nuclear operations (see "Regulatory Assets" below) and in 1998 with respect to Penn's generation operations (as described above). The fol lowing summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, compared with the respective company's total assets at December 31, 1999.
SFAS 71 Discontinued Net Assets Total Assets (In millions)
$977
$6,209 TE 530 2,667 Penn 76 1,016 Property, Plant and Equipment -
- Property, plant and equipment reflects original cost (except for CEI's, TE's and Penn's nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs.
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 annual composite rate for OE's electric plant was approximately 3.0% in 1999, 1998 and 1997. The annual composite rate for Penn's electric plant was approximately 2.5% in 1999 and 3.0% in 1998 and 1997. CEI's and TE's composite rates were both approx imately 3.4% in 1999 and 1998. In addition to the straight line depreciation recognized in 1999, 1998 and 1997, OE and Penn recognized additional capital recovery of $95 mil lion, $141 million (excluding Penn's impairment) and $172 million, respectively, as additional depreciation expense in accordance with their regulatory plans. Such additional charges in the accumulated provision for depreciation were
$517 million and $422 million as of December 31, 1999 and 1998, respectively.
Annual depreciation expense in 1999 included approxi mately $31.0 million for future decommissioning costs applicable to the Companies' ownership and leasehold inter ests in four nuclear generating units. The Companies' future decommissioning costs reflect the increase in their owner ship interests related to the asset transfer with Duquesne Light Company (Duquesne) discussed below in "Common Ownership of Generating Facilities." The Companies' share of the future obligation to decommission these units is approximately $1.8 billion in current dollars and (using a 4.0% escalation rate) approximately $4.5 billion in future dol lars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Companies have recov ered approximately $315 million for decommissioning through their electric rates from customers through December 31, 1999. If the actual costs of decommissioning the units exceed the funds accumulated from investing amounts recovered from customers, the Companies expect that additional amount to be recoverable from their cus tomers. The Companies have approximately $543.7 million invested in external decommissioning trust funds as of December 31, 1999. This includes additions to the trust funds and the corresponding liability of $123 million as a result of the asset transfer. Earnings on these funds are rein vested with a corresponding increase to the decommission ing liability. The Companies have also recognized an esti mated liability of approximately $36.7 million related to decontamination and decommissioning of nuclear enrich ment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992.
The Financial Accounting Standards Board (FASB) issued a proposed accounting standard for nuclear decom missioning costs in 1996. If the standard is adopted as pro posed: (1) annual provisions for decommissioning could increase; (2) the net present value of estimated decommis sioning costs could be recorded as a liability; and (3) income from the external decommissioning trusts could be reported as investment income. The FASB subsequently expanded the scope of the proposed standard to include other closure and removal obligations related to long-lived assets. A revised proposal may be issued by the FASB in the first quarter of 2000.
35
Common Ownership of Generating Facilities -
The Companies and Duquesne constituted the Central Area Power Coordination Group (CAPCO). The CAPCO companies formerly owned and/or leased, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The companies' portions of operating expenses associated with jointly owned facilities are included in the corresponding operating expenses on the Consolidated Statements of Income.
On March 26, 1999, FirstEnergy completed its agree ments with Duquesne to exchange certain generating assets.
All regulatory approvals were received by October 1999. In December 1999, Duquesne transferred 1,436 megawatts owned by Duquesne at eight CAPCO generating units in exchange for 1,328 megawatts at three non-CAPCO power plants owned by the Companies. The agreements for the exchange of assets, which was structured as a like-kind exchange for tax purposes, provides the Companies with exclusive ownership and operating control of all CAPCO generating units. The three FirstEnergy plants transferred are being sold by Duquesne to a wholly owned subsidiary of Orion Power Holdings, Inc. (Orion). The Companies will continue to operate those plants until the assets are transferred to the new owners. Duquesne funded decommissioning costs equal to its percentage interest in the three nuclear generating units that were transferred to FirstEnergy. The Duquesne asset transfer to the Orion subsidiary could take place by the middle of 2000. Under the agreements, Duquesne is no longer a participant in the CAPCO arrangements after the exchange.
Nuclear Fuel -
OE's and Penn's nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load.
CEI and TE severally lease their respective portions of.
nuclear fuel and pay for the fuel as it is consumed (see Note 2). The Companies amortize the cost of nuclear fuel based on the rate of consumption. The Companies' electric rates include amounts for the future disposal of spent nuclear fuel based upon the formula used to compute payments to the DOE.
Income Taxes -
Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Alternative minimum tax credits of $101 million, which may be carried forward indefinitely, are available to reduce future federal income taxes.
Retirement Benefits -
The Companies' trusteed, noncontributory defined benefit pension plan covers almost all full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. In 1998, the Centerior Energy Corporation (Centerior) pension plan was merged into the FirstEnergy pension plan. The Companies use the projected unit credit method for funding purposes and were not required to make pension contributions during the three years ended December 31, 1999. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds.
The Companies provide a minimum amount of noncon tributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Companies pay insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Companies. The Companies recognize 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.
36
The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits 1999 1998 1999 1998 (In millions)
Change in benefit obligation:
Benefit obligation as of January 1
$1,500.1
$1,327.5
$ 601.3
$ 534.1 Service cost 28.3 25.0 9.3 7.5 Interest cost 102.0 92.5 40.7 37.6 Plan amendments 44.3 40.1 Actuarial loss (gain)
(155.6) 101.6 (17.6) 10.7 Net increase from asset swap 14.8 12.5 Benefits paid (95.5)
(90.8)
(37.8)
(28.7)
Benefit obligation as of December 31 1,394.1 1,500.1 608.4 601.3 Change in plan assets:
Fair value of plan assets as of January 1 1,683.0 1,542.5 3.9 2.8 Actual return on plan assets 220.0 231.3 0.6 0.7 Company contribution 0.4 0.4 Benefits paid (95.5)
(90.8)
Fair value of plan assets as of December 31 1,807.5 1,683.0 4.9 3.9 Funded status of plan 413.4 182.9 (603.5)
(597.4)
Unrecognized actuarial loss (gain)
(303.5)
(110.8) 24.9 30.6 Unrecognized prior service cost 57.3 63.0 24.1 27.4 Unrecognized net transition obligation (asset)
(10.1)
(18.0) 120.1 129.3 Prepaid (accrued) benefit cost
$ 157.1
$ 117.1
$(434.4)
$(410.1)
Assumptions used as of December 31:
Discount rate 7.75%
7.00%
7.75%
7.00%
Expected long-term return on plan assets 10.25%
10.25%
10.25%
10.25%
Rate of compensation increase 4.00%
4.00%
4.00%
4.00%
Net pension and other postretirement benefit costs for the three years ended December 31, 1999 were computed as follows:
Other Pension Benefits Postretirement Benefits 1999 1998 1997 1999 1998 1997 (In millions)
Service cost
$ 28.3 $ 25.0 $ 15.2
$ 9.3
$ 7.5
$ 4.6 Interest cost 102.0 92.5 55.9 40.7 37.6 20.4 Expected return on plan assets (168.1) (152.7)
(99.7)
(0.4)
(0.3)
(0.2)
Amortization of transition obligation (asset)
(7.9)
(8.0)
(8.0) 9.2 9.2 8.2 Amortization of prior service cost 5.7 2.3 2.1 3.3 (0.8) 0.3 Recognized net actuarial loss (gain)
(2.6)
(0.9)
Voluntary early retirement program expense 54.5 1.9 Net benefit cost
$ (40.0) $ (43.5) $ 19.1
$62.1
$53.2
$35.2 The health care trend rate assumption is 5.3% in 2000, 5.2% in 2001 and 5.0% for 2002 and later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care trend rate assumption by one percentage point would increase the total service and interest cost compo nents by $4.5 million and the postretirement benefit obliga tion by $72.0 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $3.5 million and the postretire ment benefit obligation by $58.2 million.
Supplemental Cash Flows Information All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equiva lents on the Consolidated Balance Sheets. At December 31, 1999 and 1998, cash and cash equivalents included $83 mil lion and $26 million, respectively, to be used for the redemption of long-term debt in the first quarter of 2000 and in 1999, respectively. The Companies reflect temporary cash investments at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $36.2 million, $61.8 million and $3.0 million for the years 1999, 1998 and 1997, respectively. Commercial paper transactions of OES Fuel, Incorporated (OES Fuel) (a wholly owned subsidiary of OE) that have initial maturity periods of three months or less are reported net within financing activities under long-term debt and are reflected as long-term debt on the Consolidated Balance Sheets (see Note 3H).
37
All borrowings with initial maturities of less than one year are defined as financial instruments under generally accepted accounting principles and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approxi mate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equiv alents as of December 31:
1999 1998 Carrying Fair Carrying Fair Value Value Value Value (In millions)
Long-term debt
$6,381
$6,331
$6,783
$7,247 Preferred stock
$ 295
$ 280
$ 335
$ 340 Investments other than cash and cash equivalents:
Debt securities
-Maturity (5-10 years)
$ 475
$ 476
$ 481
$ 520
-Maturity (more than 10 years) 1,068 1,013 1,109 1,139 Equity securities 17 17 17 17 All other 852 874 520 533
$2,412
$2,380
$2,127
$2,209 The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corpo ration with credit ratings similar to the Companies' ratings.
The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms.
Investments other than cash and cash equivalents include decommissioning trust investments. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. The debt and equity securities referred to above are in the held-to-maturity category.
The Companies have no securities held for trading purposes.
Effective December 31, 1998, the Company began accounting for its commodity price derivatives, entered into specifically for trading purposes, on a mark-to-market basis in accordance with Emerging Issues Task Force Issue 98-10, "Accounting for Energy Trading and Risk Management Activities," with gains and losses recognized currently in the Consolidated Statements of Income. The contracts that were marked to market are included in the Consolidated Balance Sheets as Deferred Charges and Deferred Credits at their fair values. The impact on the consolidated financial statements was immaterial.
Regulatory Assets -
The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are being recovered from customers under the Companies' respective regulatory plans. Based on those regulatory plans, at this time, the Companies are continuing to bill and collect cost-based rates relating to all of OE's operations, CEI's and TE's nonnuclear operations, and Penn's nongeneration operations and they continue the application of SFAS 71 to those respective operations.
OE and Penn recognized additional cost recovery of $257 million, $50 million and $39 million in 1999, 1998 and 1997, respectively, as additional regulatory asset amortization in accordance with their regulatory plans. FirstEnergy's regulatory plan does not provide for full recovery of CEI's and TE's nuclear operations. As a result, in October 1997, CEI and TE discontinued application of SFAS 71 for their nuclear operations and decreased their regulatory assets of customer receivables for future income taxes related to the nuclear assets by $794 million.
The PUCO indicated that it will endeavor to issue its order related to the Company's transition plan by mid-2000.
The application of SFAS 71 to OE's generation business and the nonnuclear generation businesses of CEI and TE will be discontinued at that time. If the transition plans ultimately approved by the PUCO for OE, CEI and TE do not provide adequate recovery of their nuclear generating unit investments and regulatory assets, there would be a charge to earnings which could have a material adverse effect on the results of operations and financial condition for the Company, OE, CEI and TE. The Companies will continue to bill and collect cost-based rates for their transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those respective operations after December 31, 2000.
38
Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
1999 1998 (In millions)
Nuclear unit expenses
$1,123.0
$1,164.8 Customer receivables for future income taxes 444.3 444.0 Rate stabilization program deferrals 420.1 440.1 Sale and leaseback costs 17.8 218.7 Competitive transition charge 280.4 331.0 Loss on reacquired debt 173.9 183.5 Employee postretirement benefit costs 24.8 28.9 DOE decommissioning and decontamination costs 29.5 32.9 Other 29.6 43.5 Total
$2,543.4
$2,887.4
- 2. Leases:
The Companies lease certain generating facilities, nuclear fuel, office space and other property and equipment under cancelable and noncancelable leases.
OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsi ble, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and mainte nance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the end 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 renewal term (if elect ed) at a price equal to the fair market value of the facilities.
The basic rental payments are adjusted when applicable fed eral tax law changes.
OES Finance, Incorporated (OES Finance), a wholly owned subsidiary of OE, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits pledged to the financial institu tion providing those letters of credit are the sole property of OES Finance. In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to OE as sole owner of OES Finance common stock.
Nuclear fuel is currently financed for CEI and TE through leases with a special-purpose corporation. As of December 31, 1999, $116 million of nuclear fuel was financed under a lease financing arrangement totaling $145 million ($30 million of intermediate-term notes and $115 million from bank credit arrangements). The notes mature in August 2000 and the bank credit arrangements expire in September 2000. Lease rates are based on intermediate-term note rates, bank rates and commercial paper rates.
Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expens es on the Consolidated Statements of Income. Such costs for the three years ended December 31, 1999, are summarized as follows:
1999 1998 1997 (In millions)
Operating leases Interest element
$208.6
$201.2
$149.9 Other 110.3 147.8 45.2 Capital leases Interest element 17.5 17.6 6.1 Other 76.1 66.3 6.0 Total rentals
$412.5
$432.9
$207.2 The future minimum lease payments as of December 31, 1999, are:
Operating Leases Capital Lease Capital Leases Payments Trusts Net (In millions) 2000
$ 75.4
$ 296.5
$ 150.6 $ 145.9 2001 45.2 307.5 146.1 161.4 2002 29.7 312.7 169.5 143.2 2003 16.0 326.6 176.5 150.1 2004 12.1 291.8 110.7 181.1 Years thereafter 71.6 3,645.8 1,364.3 2,281.5 Total minimum lease payments 250.0
$5,180.9
$2,117.7 $3,063.2 Executory costs 26.9 Net minimum lease payments 223.1 Interest portion 64.8 Present value of net minimum lease payments 158.3 Less current portion 55.2 Noncurrent portion
$103.1 39
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.
- 3. Capitalization:
(A) Retained Earnings -
There are no restric tions on retained earnings for payment of cash dividends on the Company's common stock.
(B) Employee Stock Ownership Plan The Companies fund the matching contribution for their 401(k) savings plan through an ESOP Trust. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock through market purchases; the shares were converted into the Company's common stock in connection with the merger. 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 1999, 1998 and 1997, 627,427 shares, 423,206 shares and 429,515 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allo cated method. The fair value of 6,778,905 shares unallocated as of December 31, 1999, was approximately $153.8 million. Total ESOP-related compensation expense was calculated as follows:
1999 1998 1997 (In millions)
Base compensation
$18.3
$13.5
$9.9 Dividends on common stock held by the ESOP and used to service debt (4.5)
(3.9)
(3.4)
Net expense
$ 13.8
$9.6
$6.5 (C) Stock Compensation Plans -
Under the Centerior Equity Compensation Plan (Centerior Plan) adopted in 1994, common stock options were granted to management employees. Upon consummation of the merger, outstanding options became exercisable for the Company's common stock with option prices and the number of shares adjusted to reflect the merger conversion ratio. All options under the Centerior Plan expire on or before February 25, 2007.
On April 30, 1998, the Company adopted the Executive and Director Incentive Compensation Plan (FE Plan). The FE Plan permits awards to be made to key employees in the form of restricted stock, stock options, stock appreciation rights, performance shares or cash. Common stock granted under the FE Plan may not exceed 7.5 million shares. No stock appreciation rights or performance shares have been issued under the FE Plan. A total of 20,000 shares of restricted stock were granted in 1998, with a per share market price of $30.78. Restrictions on the restricted stock lapse in 25%
annual increments beginning in the fourth year from date of grant. Dividends on the 1998 grant are not restricted. An additional 8,000 shares of restricted stock were granted in 1999, in five separate awards with a weighted average market price per share of $30.89 and weighted average cliff vesting period of 5.8 years. Dividends on the 1999 grants are being restricted. Options were granted in 1998 and 1999, and are exercisable after four years from the date of grant with some acceleration of vesting possible based on perfor mance. Stock option activity for the converted Centerior Plan stock options and FE Plan stock options was as follows:
Stock Option Activity Balance at December 31, 1996 Options granted (at merger)
Options exercised Options forfeited Balance at December 31, 1997 (517,388 options exercisable)
Options granted Options exercised Options forfeited Balance at December 31, 1998 (182,330 options exercisable)
Options granted Options exercised Balance at December 31, 1999 (159,755 options exercisable)
Weighted Average Number of Exercise Options Price 743,086 222,023 3,675 517,388 189,491 335,058 7,535 364,286 1,811,658 22,575 2,153,369 23.85 22.13 22.75 24.59 29.82 24.67 29.82 27.13 24.90 21.42 25.32 40
As of December 31, 1999, the weighted average remaining contractual life of outstanding stock options was 6.2 years.
Under the Executive Deferred Compensation Plan, adopted January 1, 1999, employees can direct a portion of their Annual Incentive Award and/or Long Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout occurs three years from the date of deferral. As of December 31, 1999, there were 61,465.81 stock units outstanding.
The Company continues to apply APB Opinion 25, "Accounting for Stock Issued to Employees." As required by SFAS 123, "Accounting for Stock-Based Compensation,"
the Company has determined pro forma earnings as though the Company had accounted for employee stock options under the fair value method. The weighted average assump tions used in valuing the options and their resulting fair values are as follows:
1999 1998 1997 Valuation assumptions:
Expected option term (years) 6.4 10 8
Expected volatility 20.03%
15.50%
16.00%
Expected dividend yield 5.97%
5.68%
5.80%
Risk-free interest rate 5.97%
5.65%
5.94%
Fair value per option
$3.42
$3.25
$2.92 The pro forma effects of applying fair value accounting to the Company's stock options would be to reduce net income and earnings per share. The following table summarizes the pro forma effect.
1999 1998 Net Income (000)
As Reported
$568,299
$410,874 Pro Forma
$567,876
$410,839 Earnings Per Share of Common Stock Basic and Diluted As Reported
$2.50
$1.82 Pro Forma
$2.50
$1.82 (D) Comprehensive Income -
In 1998, the Company adopted SFAS 130, "Reporting Comprehensive Income," and applied the standard to all periods presented in the Consolidated Statements of Common Stockholders' Equity. 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.
(E) Preferred and Preference Stock Penn's 7.75% series of preferred stock has a restriction which prevents early redemption prior to July 2003. OE's 8.45% series of preferred stock has no optional redemption provision. CEI's $88.00 Series R preferred stock is not redeemable before December 2001 and its $90.00 Series S has no optional redemption provision. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice.
Preference stock authorized for the Companies are 8 mil lion shares without par value for OE; 3 million shares with out par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding.
(F) Preferred Stock Subject to Mandatory Redemption -
Annual sinking fund provisions for the Companies' preferred stock are as follows:
Redemption Price Per Series Shares Share Date Beginning OE 8.45%
50,000
$ 100 (i)
$ 7.35 C 10,000 100 (i) 88.00 E 3,000 1,000 (i) 91.50 Q 10,714 1,000 (i) 90.00 S 18,750 1,000 (i) 88.00 R 50,000 1,000 December 1 2001 Penn 7.625%
7,500 100 October 1 2002 (i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are $38 million in 2000, $85 million in 2001, $19 million in 2002, $2 million in 2003 and $2 million in 2004. A liability of $19 million was included in the net assets acquired from CEI and TE for preferred dividends declared attributable to the post-merger period. Accordingly, no accruals for CEI and TE preferred dividends are included in the Company's Consolidated Statement of Income for the period November 8, 1997 through December 31, 1997.
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(G) Ohio Edison Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Ohio Edison Subordinated Debentures -
Ohio Edison Financing Trust, a wholly owned subsidiary of OE, has issued $120 million of 9% Cumulative Trust Preferred Capital Securities. OE purchased all of the Trust's Common Securities and simultaneously issued to the Trust $123.7 mil lion principal amount of 9% Junior Subordinated Debentures due 2025 in exchange for the proceeds that the Trust received from its sale of Preferred and Common Securities.
The sole assets of the Trust are the Subordinated Debentures whose interest and other payment dates coincide with the distribution and other payment dates on the Trust Securities.
Under certain circumstances, the Subordinated Debentures could be distributed to the holders of the outstanding Trust Securities in the event the Trust is liquidated. The Subordinated Debentures may be optionally redeemed by OE beginning December 31, 2000, at a redemption price of
$25 per Subordinated Debenture plus accrued interest, in which event the Trust Securities will be redeemed on a pro rata basis at $25 per share plus accumulated distributions.
OE's obligations under the Subordinated Debentures along with the related Indenture, amended and restated Trust Agreement, Guarantee Agreement and the Agreement for expenses and liabilities, constitute a full and unconditional guarantee by OE of payments due on the Preferred Securities.
(H) Long-Term Debt -
The first mortgage indentures and their supplements, which secure all of the Companies' first mortgage bonds, serve as direct first mort gage liens on substantially all property and franchises, other than specifically excepted property, owned by the Companies.
Based on the amount of bonds authenticated by the Trustees through December 31, 1999, OE's, TE's and Penn's annual sinking and improvement fund requirements for all bonds issued under the mortgage amounts to $31 million.
OE, TE and Penn expect to deposit funds in 2000 that will be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenti cated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are:
(In millions) 2000
$668.8 2001 375.7 2002 945.8 2003 459.0 2004 833.3 The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds and, in some cases, by subordinate liens on the related pollution control facilities. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $397.3 million. To the extent that drawings are made under those letters of credit to pay principal of, or interest on, the pollution control revenue bonds, OE, Penn and/or CEI are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 0.43% to 1.10% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder.
42
OE had unsecured borrowings of $190 million at December 31, 1999, supported by a $250 million long-term revolving credit facility agreement which expires November 18, 2002. OE must pay an annual facility fee of 0.20% on the total credit facility amount. In addition, the credit agree ment provides that OE maintain unused first mortgage bond capability for the full credit agreement amount under OE's indenture as potential security for the unsecured borrowings.
CEI and TE have letters of credit of approximately $222 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in May 2002. The letters of credit are secured by first mortgage bonds of CEI and TE in the proportion of 40% and 60%, respectively (see Note 2).
OE's and Penn's nuclear fuel purchases are financed through the issuance of OES Fuel commercial paper and loans, both of which are supported by a $180.5 million long term bank credit agreement which expires March 31, 2001.
Accordingly, the commercial paper and loans are reflected as long-term debt on the Consolidated Balance Sheets. OES Fuel must pay an annual facility fee of 0.20% on the total line of credit and an annual commitment fee of 0.0625% on any unused amount.
- 4. Short-Term Borrowings and Bank Lines of Credit:
Short-term borrowings outstanding at December 31, 1999, consisted of $257.8 million of bank borrowings and
$160.0 million of OES Capital, Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned sub sidiary of OE whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expires in 2002.
The Companies have various credit facilities with domestic banks that provide for borrowings of up to $205 million under various interest rate options. OE's short-term borrow ings may be made under its lines of credit on its unsecured notes. To assure the availability of these lines, the Companies are required to pay annual commitment fees that vary from 0.125% to 0.50%. These lines expire at various times during 2000. The weighted average interest rates on short-term borrowings outstanding at December 31, 1999 and 1998, were 6.51% and 5.67%, respectively.
- 5. Commitments and Contingencies:
Capital Expenditures -
The Companies' current forecasts reflect expenditures of approximately
$3.0 billion for property additions and improvements from 2000-2004, of which approximately $650 million is applicable to 2000. Investments for additional nuclear fuel during the 2000-2004 period are estimated to be approximately
$497 million, of which approximately $159 million applies to 2000. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately
$480 million and $106 million, respectively, as the nuclear fuel is consumed.
Stock Repurchase Program -
On November 17, 1998, the Board of Directors authorized the repurchase of up to 15 million shares of the Company's common stock over a three-year period beginning in 1999. Repurchases are made on the open market, at prevailing prices, and are funded primarily through the use of operating cash flows. During 1999, the Company repurchased and retired 4.6 million shares of its common stock at an average price of $28.08 per share. The Company also entered into a forward contract with Credit Suisse First Boston Corporation for the purchase of 1.4 million shares of the Company's common stock at an average price of $24.22 per share to be settled on November 3, 2000. The contract may be settled through gross physical settlement, net share settlement or net cash settlement at the Company's election.
43
Nuclear Insurance -
The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retro spective rating plan. The Companies' maximum potential assessment under the industry retrospective rating plan would be $352.4 million per incident but not more than $40 million in any one year for each incident.
The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Companies have also obtained approximately $1.43 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately
$44 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.
The Companies intend to maintain insurance against nuclear risks as described above as long as it is available.
To the extent that replacement power, property damage, decontamination, decommissioning, 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.
Environmental Matters -
Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters.
The Companies estimate additional capital expenditures for environmental compliance of approximately $292 million, which is included in the construction forecast provided under "Capital Expenditures" for 2000 through 2004.
The Companies are in compliance with the current sulfur dioxide (SO2) and nitrogen oxides (NOx) reduction require ments under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or purchasing emission allowances. NOx reductions are being achieved through combustion controls and generating more electricity from lower-emitting plants. In September 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities by May 2003.
The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions across a region of twenty-two states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. In May 1999, the U.S. Court of Appeals for the D.C. Circuit issued a stay which delays implementation of EPA's NOx Transport Rule until the Court has ruled on the merits of various appeals. Under the NOx Transport Rule, each of the twenty-two states are required to submit revised State Implementation Plans (SIP) which comply with individual state NOx budgets established by the EPA contemplating an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions. A proposed Federal Implementation Plan accompanied the NOx Transport Rule and may be implemented by the EPA in states which fail to revise their SIP. In another separate but related action, eight states filed petitions with the EPA under Section 126 of the Clean Air Act seeking reductions of NOx emissions which are alleged to contribute to ozone pollution in the eight petitioning states. The EPA suggests that the Section 126 petitions will be adequately addressed by the NOx Transport Program, but a December 17, 1999 rulemaking established an alternative program which would require nearly identical 85% NOx reductions at 392 utility plants, including the Companies' Ohio and Pennsylvania plants, by May 2003, in the event implementation of the NOx Transport Rule is delayed. New Section 126 petitions were filed by New Jersey, Maryland, Delaware and the District of Columbia in mid-1999 and are still under evaluation by the EPA. The Companies continue to evaluate their compliance plans and other compliance options.
44
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 $27,500 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.
In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit remanded both standards back to the EPA finding constitutional and other defects in the new NAAQS rules. The D.C. Circuit Court, on October 29, 1999, denied an EPA petition for rehearing. The Companies cannot predict the EPA's action in response to the Court's remand order. The cost of compliance with these regulations, if they are reinstated, may be substantial and depends on the manner in which they are ultimately implemented, if at all, by the states in which the Companies operate affected facilities.
In September 1999, FirstEnergy received, and subse quently in October 1999, OE and Penn received, a citizen suit notification letter from the New York Attorney General's office alleging Clean Air Act violations at the W. H. Sammis Plant. In November 1999, OE and Penn received a citizen suit notification letter from the Connecticut Attorney General's office alleging Clean Air Act violations at the Sammis Plant. On November 3, 1999, the EPA issued Notices of Violation (NOV) or a Compliance Order to eight utilities covering 32 power plants, including the Sammis Plant. In addition, the U.S. Department of Justice filed seven civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S.
District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of this litigation, the Company believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and com plaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. It is anticipated at this time that the Samnis Plant will continue to operate while the matter is being decided.
CEI and TE have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. CEI and TE have accrued liabilities totaling $5.4 million as of December 31, 1999, based on estimates of the costs of cleanup and the proportionate responsibility of other PRPs for such costs.
CEI and TE believe that waste disposal costs will not have a material adverse effect on their financial condition, cash flows or results of operations.
- 6. Segment Information:
The Company's primary segment is its Electric Utility Operating Companies which includes four regulated electric utility operating companies that provide electric service in Ohio and Pennsylvania. Its other material business segment is FETS which markets and trades electricity in nonregulated markets. Financial data for these business segments and products and services are as shown on the following page:
45
Segment Financial Information Electric FE Trading All Reconciling Utilities Services Other Eliminations Totals (In millions) 1999 External revenues
$ 5,421
$191
$ 708
$ 6,320 Intersegment revenues 32 60 102 (194)
Total revenues 5,453 251 810 (194) 6,320 Depreciation and amortization 913 25 938 Net interest charges 549 6
66 (49) 572 Income taxes 377 (5) 23 395 Net income/Earnings on common stock 545 (8) 35 (4) 568 Total assets 17,105 181 1,864 (926) 18,224 Property additions 417 130 547 Acquisitions 25 53 78 1998 External revenues
$ 5,215
$411
$ 249
$ 5,875 Intersegment revenues 32 26 97 (155)
Total revenues 5,247 437 346 (155) 5,875 Depreciation and amortization 748 11 759 Net interest charges 590 2
69 (60) 601 Income taxes 320 (35)
(2) 283 Extraordinary item:
Pennsylvania restructuring (31)
(31)
Net income/Earnings on common stock 478 (52) 1 (16) 411 Total assets 18,316 54 1,742 (1,920) 18,192 Property additions 304 64 368 Acquisitions 285 285 1997 External revenues
$ 2,844
$ 43 74
$ 2,961 Intersegment revenues 33 106 (139)
Total revenues 2,877 43 180 (139) 2,961 Depreciation and amortization 470 5
475 Net interest charges 300 60 (51) 309 Income taxes 206 3
209 Net income/Earnings on common stock 335 (1) 4 (32) 306 Total assets 18,700 32 1,209 (1,680) 18,261 Property additions 166 38 204 Acquisitions 1,582 1,582 Products and Services Oil & Gas Energy Related Electricity Sales and Sales and Year Sales Production Services (In millions) 1999
$5,253
$203
$503 1998 4,980 26 198 1997 2,775 46
- 7. Summary of Quarterly Financial Data (Unaudited):
The following summarizes certain consolidated operating results by quarter for 1999 and 1998.
Three Months Ended March 31, June 30, September 30, December 31, 1999 1999 1999 1999 (In millions, except per share amounts)
Revenues
$1,417.4
$1,523.9
$1,732.4
$1,645.9 Expenses 1,041.7 1,149.8 1,291.0 1,301.7 Income Before Interest and Income Taxes 375.7 374.1 441.4 344.2 Net Interest Charges 146.1 147.4 141.3 137.5 Income Taxes 92.9 101.4 114.3 86.2 Net Income
$ 136.7 $ 125.3
$ 185.8
$ 120.5 Earnings per Share of Common Stock
$.60
$.55
$.82
$.53 March 31, June 30, September 30, December 31, Three Months Ended 1998 1998 1998 1998 (In millions, except per share amounts)
Revenues
$1,367.1
$1,464.0
$1,722.0
$1,321.8 Expenses 1,016.8 1,197.1 1,294.0 1,020.8 Income Before Interest and Income Taxes 350.3 266.9 428.0 301.0 Net Interest Charges 143.6 154.7 153.3 149.4 Income Taxes 83.0 52.2 111.7 56.9 Income Before Extraordinary Item 123.7 60.0 163.0 94.7 Extraordinary Item (Net of Income Taxes)
(Note 1)
(30.5)
Net Income
$ 123.7 $
29.5
$ 163.0
$ 94.7 Earnings per Share of Common Stock Before Extraordinary Item
$.56
$.27
$71
$.41 Extraordinary Item (Net of Income Taxes)
(Note 1)
(.14)
Earnings per Share of Common Stock
$.56
$13
$71
$.41
- 8. Pro Forma Combined Condensed FirstEnergy Statement of Income (Unaudited):
The Company was formed on November 8, 1997 by the merger of OE and Centerior. The merger was accounted for as a purchase of Centerior's net assets with 77,637,704 shares of FirstEnergy Common Stock through the conver sion of each outstanding Centerior Common Stock share into 0.525 of a share of FirstEnergy Common Stock (frac tional shares were paid in cash). Based on an imputed value of $20.125 per share, the purchase price was approximately
$1.582 billion, which also included approximately $20 mil lion of merger related costs. Goodwill of approximately $2.0 billion was recognized (to be amortized on a straight-line basis over forty years), which represented the excess of the purchase price over Centerior's net assets after fair value adjustments.
Accumulated amortization of goodwill was approximately
$109 million as of December 31, 1999. The merger purchase accounting adjustments, which were recorded in the records of Centerior's direct subsidiaries, included recognizing estimated severance and other compensation liabilities ($80 million). The amount charged against the liability in 1998 relating to the costs of involuntary employee separation was $41 million. In addition, the liability was reduced to approximately $9 million as of December 31, 1998 to represent potential costs associated with the separation of 493 CEI employees. The liability adjustment was offset by a corresponding reduction to goodwill recognized in connection with the Centerior acquisition.
The following pro forma statement of income of FirstEnergy gives effect to the OE/Centerior merger as if it had been consummated on January 1, 1997, with the purchase accounting adjustments actually recognized in the business combination.
Year Ended December 31, 1997 (In millions, except per share amounts)
Revenues
$5,206 Expenses 3,800 Income Before Interest and Income Taxes 1,406 Net Interest Charges 643 Income Taxes 336 Net Income
$ 427 Earnings per Share of Common Stock
$ 1.92 Pro forma adjustments reflected above include: (1) adjusting CEI and TE nuclear generating units to fair value based upon independent appraisals and estimated discounted future cash flows based on management's estimate of cost recovery; (2) goodwill recognized representing the excess of the purchase price over Centerior's adjusted net assets; (3) elimination of revenue and expense transactions between OE and Centerior; (4) amortization of the fair value adjustment for long-term debt; and (5) adjustments for estimated tax effects on the above adjustments.
47
FIRSTENERGY CORP.
Consolidated Financial and Pro Forma Combined Operating Statistics (Unaudited)
GENERAL FINANCIAL INFORMATION (Dollars in thousands)
Revenues Net Income SEC Ratio of Earnings to Fixed Charges Net Property, Plant and Equipment Capital Expenditures Total Capitalization 1999
$ 6,319,647 568,299 2.01
$ 9,093,341 474,118
$11,469,795 Capitalization Ratios:
Common Stockholders' Equity 39.8%
Preferred and Preference Stock:
Not Subject to Mandatory Redemption 5.7 Subject to Mandatory Redemption 2.2 Long-Term Debt 52.3 Total Capitalization 100.0%
Average Capital Costs:
Preferred and Preference Stock Long-Term Debt COMMON STOCK DATA (a)
Earnings per Share Return on Average Common Equity Dividends Paid per Share Dividend Payout Ratio Dividend Yield Price/Earnings Ratio Book Value per Share Market Price per Share Ratio of Market Price to Book Value OPERATING STATISTICS (b)
Kilowatt-Hour Sales (Millions):
Residential Commercial Industrial Other Total Retail Total Wholesale Total Sales Customers Served:
Residential Commercial Industrial Other Total Number of Employees (Excludes Facilities Services Group and MARBEL) (c) 1998 1997 1996
$ 5,874,906 410,874 1.77
$ 9,242,574 305,577
$11,756,422 37.9%
5.6 2.5 54.0 100.0%
$ 2,961,125 305,774 2.18
$ 9,635,992 188,145
$12,124,492 34.3%
5.5 2.7 57.5 100.0%
$2,521,788
$ 302,673 2.38
$5,534,382
$ 145,005
$5,582,989 44.8%
3.8 2.8 48.6 100.0%
1995
$2,500,770
$ 294,747 2.32
$5,788,436
$ 196,041
$5,565,997 43.3%
3.8 2.9 50.0 100.0%
1994
$2,390,957
$ 281,852 2.24
$5,904,445
$ 258,642
$5,852,030 39.6%
5.6 0.7 54.1 100.0%
7.99%
8.01%
8.02%
7.59%
7.59%
7.15%
7.65%
7.83%
8.02%
7.76%
8.00%
8.17%
$2.50 12.7%
$1.50 60%
6.6%
9.1
$20.22
$22.69 112%
16,933 18,295 24,884 371 60,483 7,135 67,618 1,951,928 219,761 11,667 2,177 2,185,533
$1.95 10.3%
$1.50 77%
4.6%
16.7
$19.37
$32.56 168%
15,873 16,255 24,039 378 56,545 5,557 62,102 1,938,259 214,698 11,888 2,067 2,166,912
$1.94 11.0%
$1.50 77%
5.2%
14.9
$18.71
$29.00 155%
15,562 15,868 24,062 372 55,864 7,870 63,734 1,929,371 215,307 12,918 2,040 2,159,636
$2.10 12.4%
$1.50 71%
6.6%
10.8
$17.35
$22.75 131%
15,807 14,944 23,367 1,158 55,276 9,670 64,946 1,912,850 212,092 12,974 3,913 2,141,829 10,034**
8,765 10,020 1
10,477
$2.05 12.5%
$1.50 73%
6.4%
11.5
$16.73
$23.50 140%
15,773 14,845 22,681 1,196 54,495 9,295 63,790 1,907,850 210,745 12,763 3,869 2,135,227
$1.97 12.4%
$1.50 76%
8.1%
9.4
$16.15
$18.50 115%
15,181 14,366 21,910 1,218 52,675 7,039 59,714 1,893,827 207,362 12,618 3,760 2,117,567 1989
$2,193,852
$ 332,932 2.03
$6,088,598
$ 258,041
$6,083,504 42.2%
5.8 1.5 50.5 100.0%
8.72%
9.67%
$2.18 13.0%
$1.96 90%
8.3%
10.9
$16.82
$23.75 141%
14,425 13,064 22,315 1,135 50,939 9,416 60,355 1,833,955 195,888 12,517 3,965 2,046,325 (a) Before exsraordinary charge in 1998.
(b) Years prior to 1998 rejlectprforma combined Ohio Edison and Centerior statistics.
(c) 1999 number of employees includes approximately 1,100 Beaver Valley Power Station employees added as a result of the generation plant asset swap.
Printed on recycled paper.
48 11,633 11,933 15,967
Shareholder INFORMATION Investor Services, Transfer Agent and Registrar We act 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 infor mation, can send their stock or write to Investor Services, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. Shareholders also can call the following toll free 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: 800-736-3402.
For Internet access to shareholder information and useful forms, visit our Web site at: wwwfirstenergycorp.corrir on the Internet.
Stock Listings and Trading Newspapers generally report FirstEnergy common stock under the abbreviation FSTENGY, but this can vary depend ing upon the newspaper. The common stock of FirstEnergy and preferred stock of its electric utility subsidiaries are list ed on the following stock exchanges:
Company Stock Exchange Symbol FirstEnergy New York FE The Illuminating Company New York, OTC CVX Ohio Edison New York OEC Pennsylvania Power Philadelphia PPC Toledo Edison New York, OTC, TED American Dividends Proposed dates for the payment of FirstEnergy common stock dividends in 2000 are:
Ex-Dividend Date Record Date Payment Date February 3 February 7 March 1 May 3 May 5 June 1 August 3 August 7 September 1 November 3 November 7 December 1 Direct Dividend Deposit Shareholders can have their dividend payments automati cally deposited to checking and savings accounts at any financial institution that accepts electronic direct deposits.
Use of this free service ensures that payments will be avail able to you on the payment date, eliminating the possibility of mail delay or lost checks. To receive an authorization form, contact Investor Services.
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 share holders 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 $25 per payment up to $100,000 annually. To receive an enrollment form, contact Investor Services.
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 stock certificate(s) to the Company along with a signed let ter requesting that the Company hold the shares. They should also 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 divi dend checks or Stock Investment Plan statements.
Combining Stock Accounts If you have more than one stock account and want to combine them, please write or call Investor Services and specify the account that you want to retain as well as the registration of each of your accounts.
Duplicate Mailings of the Annual Report If you hold stock in more than one registration and do not wish to combine accounts, you can eliminate duplicate mail ings of our annual report by informing us when voting your shares for the Annual Meeting of Shareholders. You also can send a written request, including the exact registration of the account for which you want the mailing discontinued, to Investor Services.
Form 10-K Annual Report Form 10-K, the Annual Report to the Securities and Exchange Commission, will be sent without charge by writ ing to Nancy C. Ashcom, 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, Manager, Investor Relations, 330-384-5500.
Annual Meeting of Shareholders Shareholders are invited to attend the 2000 Annual Meeting of Shareholders on Thursday, April 27, at 10 a.m.,
at the John S. Knight Center in Akron, Ohio. Registered holders of common stock not attending the meeting can appoint a proxy and vote on the items of business by tele phone, 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 10, 2000.
49
Presorted Std.
F s 76 South Main Street Akron, Ohio 44308-1890 U.S. Postage www.firstenergycorp.com PAID Akron, Ohio Permit No. 561 1999 ANNUAL R E POR T