ML20207E576
| ML20207E576 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 12/31/1998 |
| From: | CLEVELAND ELECTRIC ILLUMINATING CO. |
| To: | |
| Shared Package | |
| ML20207E531 | List: |
| References | |
| NUDOCS 9906070080 | |
| Download: ML20207E576 (29) | |
Text
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ANNUAL REPORT 1998 2
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 1998 ANNUAL REPORT TO STOCKHOLDERS I i
The Cleveland Electric illuminating Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It provides electric services to communities in an area of 1,700 square miles in northeastem Ohio, including the City of Cleveland. It also i provides electric energy at wholesale to other electric companies and to certain municipalities in its service area.
i Gentents East Consolidated Financial and Operating Statistics . . . . . . 1 Management's Discussion and Analysis,= . . . . . . . . . . 2-7 Consolidated Statements of income , . . . . . . . . . . . . . . . . . . . . . . 8 Consolidated Balance Sheets... .. ...... .. . . .. . 9 Consolidated Statements of Capitalization . .. . .. . 10-11 i Consolidated Statements of Common Stockholder's Equity... . . . . 12 )
Consolidated Statements of Preferred Stock.. . . . . . . . . . . 12 Consolidated Statements of Cash Flows ... .. . .. . . . . .. 13 Consolidated Statements of Taxes... . . .. ... . . . . . . . . .. 14 Notes to Consolidated Financial Statements. . . . . . . . . . . . . . 15-26 Report of independent Public Accountants.. . . . ... .. . . . . . . 27 l
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c THE CLEVELAND ELECTRIC ILLUMINATING COMPANY l I
CONSOLIDATED FINANCIAL AND OPERATING STATISTICS l
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Nov. 8 - Jan.1- i
, 1998 Dec. 31,1997 Nov. 7.1997 1996 1995 1994 (Dollars in mousands) i GENERAL FINANCIALINFORMATION: )
Opemting Revenues . . $ 1.782.376 $ 253.963 $ 1,529.014 $ 1.789.961 $ 1.768.737 $ 1.698,021 l I
Operating income $ 368.902 3 49.502 $ 307.332 $ 358.620 $ 397,899 $ 396 009 1
income Before Extraordinary item $ 164.891 $ 19290 95.191 $ 116 553 $ 183.719 $ 185.431
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Net income (Loss). . $ 164.891 $ 19 290 $ (229.247) $ 116 553 $ 183.719 $ 185.431 Eamings (Loss)on Common Stock $ 140.097 $ 19.290 $ (274 276) $ 77.810 $ 141 275 $ 139.994 ,
1 Net Utility Plant.. $ 3.074.043 $ 3,156,659 $ 4.983.219 $ 5.090 315 $ 5191.628 Total Assets $ 6.318.183 $ 6,440.284 $ 6.962.297 $ 7.222.416 $ 7204,045 1
l CAPITALIZATION.
Common Stockholder's Equity $ 1,008.238 $ 950.904 $1,044.283 $ 1,126,762 $ 1,058,190 Preferred Stock-Not Subject to Mandatory Redemption. 238,325 238,325 238,325 240.871 240,871 Subject to Mandatory Rt.demption 149.710 183,174 186,118 215,420 245,971 j Lon9-Term Debt. . 2.888.202 3.189.590 2.523.030 2.759.492 2.683207 i Total Capitalization . $ 4284 475 $ 4,561.993 $ 3 991,756 54.342.545 $ 4,228 239 I
CAPITALIZATION RATIOS:
Common Stockholder's Equity. . 23.5 % 20.9'A 26.2 % 25.9 % 25.0%
Preferred Stock-Not Subject to Mandatory Redemption.. . 5.6 5.2 6.0 5.6 5.7 Subject to Mandatory Redemption . 3.5 4.0 4.6 5.0 5.8 Long. Term Debt . 67.4 69.9 63.2 _63 5 63.5 TotalCapitalization - 100 0% 100 0% 100.0 % 100.0 % 100 0%
KILOWATT. HOUR SALES (Millions):
Resglential 4,949 790 4,062 4,958 5,063 4,924 Commercial 6.353 893 4.990 5.908 5.946 5.770 industnal-- 8.024 1,285 6,710 7,977 7.994 7,970 Other 165 89 476 522 _ 550 575 Total Retall 19,491 3,057 16,238 19,365 19,553 19.239 Total Wholesale . , . . . . 1.275 575 2.408 2.155 1.694 1.073 Total . 20.766 3 632 18.646 21.520 21.247 20.312 CUSTOMERS SERVED (Year.End):
Residential .
668,470 671,265 663,130 669,725 668,346 Commercial . . . . . . 68,896 74,751 70.886 72.259 71.609 Industrial 5,336 6.515 6,545 6.649 6.993
,. Other.- _ 221 278 446 442 417 Total . 742.923 752.809 741.007 749.075 747.365 r Average Annual Residential kWh Usage 7.395 7.235 7,451 7.570 7,370 Peak Load. Megawatts.. .. .. .
4,248 3,955 3,938 4,049 3,740 Number of Employees (Year.End). 1,798 3,162 3,282 3.636 3,547 1
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND '
ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that are subsect to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms an#cipale, poten#al, expect, be# eve, es# mete and similar words. Actual results m.y differ materially due to the speed and nature of increased competition and deregulation in the electric utility. industry, economic or weather conditions affectmg future sales and margins, changes in markets for energy services, changing energy market pricos, legislative and regulatory chan9es, and the availability and cost of capital and other
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similar factors.
Results of Operations We conhnued to take steps in 1998 to better position our Company as cu,C 6 continues to expand in the electric utility industry. Investments were made in new informahon systems with enhanced funce ;;y which also address Year 2000 afWieakri deficiencies. We also contributed to the 1998 cash savings of FirstEnergy Corp.
(FwstEnergy) totahng $t73 mHllon. These savings were captured from initiatives implemented during the year in connection with merger-related economies made possible by FirstEnergy's formation through the merger of our former parent company, Centenor Energy Corporation, and Ohio Edison Company on November 8,1997, Financial results renect the application of purchase accounting to the merger. This accounting resulted in fair value adjustments, which were " pushed down" or renected on the separate Anancial statements of Centerior's direct subsidiaries as of the merger date, including our financel statements. As a result, we recorded purchase accounting fair value adjustments to: (1) revolue our nuclear generating units to fair value, (2) adjust long-term debt to fair value, (3) adjust our retirement and severance benent liabilities, and (4) record goodwill. Accordingly, the post-merger financial statements reflect a new basis of accounting, and separate financial statements are presented for the pre-merger and post-merger penods. For the remainder of this discussion, for categories substantiaHy unaffected by the merger and with no significant pre-merger or post-merger accounting events, we have combined the 1997 pre-merger and post-merger periods and have compared the total to 1998 and 1998.
Eamings on common stock were $140.1 minion in 1998. Results for 1998 were adversely affected by sharp increases in the spot market price for electricity occasioned by a constrained power supply and heavy customer demand in the latter part of June 1998, combmed with unscheduled generahng unit outages, which readied in spot market purchases of power at prices which substantially arrandad amounts recovered from retan %stomers. Pro.
merger sammgs on common stock in 1997 included an October 1997 write-off of certain regulaton' assets. Excluding this write-off, pre-merger eamings on common stock were $50.2 million. For the seven-weelt post-merger period, esmings on common stock were $19.3 minion. Eammgs on common stock were $77.8 million in 998.
Operating revenues decreased slightly in 1998 following a decline the provi%s year. The followng table summertzes the sources of decreases in operating revenues for 1998 and 1997 as compared to the prior year:
1908 1901 tih masens)
Chengo in reted kilowett hour sales - 8 12.7 8 (9.8) change in average retes prios _ 5.9 (4.8) whoissais sales (15.7) 18.6 Oeier - (3.5) fitc)
Notr__ gro.8) $ (TO) ,,
~ Total kHowatt-hour sales were down in 1998 from the prior year after establishing a new record for s
kHowatt-hours sold in 1997. The dochne was due to a 57.5% decrease in sales to wholesale customers. Several generating unit outages, described later in this report, reduced energy available for sale to the wholesale market. Retan sales were up in 1998, compared to 1997, with an increase of 0.5%. Kilowatt-hour sales to residential and swT,,s,i.:
customers increased 1.5% and 0.3%, respectively, while industrial sales remamed nearly unchanged from the previous year. In 1997, retail sales decreased 0.4% with a small increase in sales to industrial customers more than offset by a 2
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. 2.2% decrease in residential kilowatt-hour sales and a 0.4% reduction in commercial kilowatt-hour sales from the previous year. However, overall there was a 3.5% increase in idlowatt-hour sales due to an increase in sales to whoisaale customers.
Operation and maintenance expenses were nearly unchanged in 1998, compared to the prior year, due to increased fuel and purchased power costs substantially offset by a decrease in nuclear operating costs and other operating costs. Most of the increase in fuel and purchased power occurred in the second quarter and resulted from
- ,a comtunation of factors. In late June 1998, the midwestem and southem regions of the United States experienced
. electricity shortages caused mainly by record temperatures and humidity and unscheduled generating unit outages.
During this period, Beaver Valley Unit 2 was out of service and the Davis-Besse plant was removed from service as a result of damage to transmission facMities caused by a tomado. As a result, we purchased significant amounts of power or the spot market at unusually high prices, causing the increase in purchased power costs. An increase in purchewed power costs also contributed to the 1997 increase in fuel and purchased power costs, compared to 1996, which was offset in part by lower fuel costs caused by an increase in the mix of nuclear generation to coal-fired generation. Nuclear operating costs were lower in 1998, compared to 1997, reflectmg reduced costs at the Perry Plant partially offset by increased costs at the Beaver VaNey and Davis-Besse plants. Lower nuclear operating costs i in 1997 resulted from lower costs at the Feny and Davis-Besse plants offset in part by increased costs at the Beaver l Vaney Plant. Other operating costs in 1998 were lower partiaNy due to the absence of a 1997 pre-merger charge for !
estimated severance costs totaling $9.9 minion. In comparing other operating costs in 1997 and 1996, the effect of I the 1997 charge was more than offset by an $11.9 million charge in 1996 for disposal of obsolete materials and supplies. Both 1998 and 1997 benefited from ongoing cost cuttmg and the effect of work force reductions.
Lower deprar'iahia asset helences, resulting from the purchase accountmg adjustment, reduced depreciation and amortization in the 1998 and 1997 post-merger period. These reductions were partiaHy offset by the amortization of goodwill recognized with the arWaHan of purchase accounting DeproCIshon and amortization in the 1997 pre merger period increased principeHy due to changes in depreciabon rates approved in the AprH 1996 Public UtHities Commission of Ohio (PUCO) rate order.
Interest income on trust notes acquired in connection with the Bruce Mansfield Plant lease refinancing (see Note 2), which began in June 1997, increased other income in 1998 and the 1997 post-merger penod. In the pre-merger penod of 1997, interest income on the trust notes was more than offset by merger-related expenses and -
costs associated with the accounts receivable securitization. Total interest charges decreased in 1998 principally due to the amortization of premiums associated with the revaluation of long-terrri debt in connechon with the merger, which also contributed to the decrease in interest charges in the post-merger penod of 1997. In the pre-merger period of 1997, interest charges were higher because interest on nem secured notes and short-term borrowings for the Bruce Mansfleid Plant lease refinancing exceeded the expense reduction from the redemption and refinancing of debe s.curmes.
Preferred stock dividend requirements in 1998 were reduced by $9 mHlion and in 1997 were increased by \
' $9 million due to the declaration of preferred dividends as of the merger date for dividends attributable to the post- ;
merger period (see
- Preferred and Proforence Stock"in Note 3c).
capital Resources and t.iquidity we continue to actively pursue economic rennoncinos and optional redemphons to reduce the cost of debt and preferred stock, and improve our financial position. A total of $230 mHlion of long-term debt refinancmg was completed during 1996. We -i- d $150 mHlion of optional redemptions. During 1998, we reduced our total debt by
.w,A , $210 mHHon. Our common stockholder's equity percentage of capitehzation increased to 24% st December 31,1998 from 21% at the end of the previous year. The merger resulted in improved credit ratings in 1997, l which have lowered the cost of now issues. The foHowing table summenzos changes in credit ratings resulting from the merger:
Pen. sterner Past.hterner standard Isoody's standard Isoody's :
.c & Poor's investors & Poor's Irwestors !
carnaration servios. Inc. Cornorneinn servian. ine.
First mortssos bonds 88 Ba2, BB+ Bai e Subordinated detM B+ Bs3 BB- Bs3 Preferred Stod( B b2 BB- bi 1
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Excluding the effect of the Bruce Mansfield Plant lease refinancing, interest costs on long-term debt were reduced by approximately $18 million in 1998, cornpared to 1997. Through economic refinancings and redemptions of higher cost debt we have reduced the average cost of outstanding debt from 8.82% in 1993 to 8.15% in 1997 and 7.99% in 1998. We continue to streamline our operations, as evidenced by a 50% increase in FirstEnergy's ,
customer / employee ratio, which has increased from 165 at the end of 1993 to 247 as of December 31,1998. Merger.
related savings through consolidation of activities have contributed to these r6sults.
Our cash requirements in 1999 for operating expenses, construction expenditures and scheduled debt ;
maturities are expected to be met without issuing additional securities. We have cash requirements of approximately
$885.6 million for the 1999-2003 period to meet scheduled maturities of long-term debt and preferred stock, Of that -
amount, approximately $178.0 million applies to 1999.
We had about $73.0 million of cash and temporary investments and no short-term indebtedness on December 31,1998. Upon completion of the merger, application of purchase accounting reduced bondable property such that we are not currently able to issue additional first mortgage bonds, except in connection with refinancing.
Together with The Toledo Edison Company, as of December 31,1998, we had unused borrowing capability of $100 million under a FirstEnergy revolving line of credit.
Our capital spending for the period 1999-2003 is expected to be about $701 million (excluding nuclear fuel), of which approximately $150 million applies to 1999. Investments in additional nuclear fuel during the 1999-2003 period are estimated to be approximately $130 million, of which about $14 million applies to 1999. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $150 million and $32 million, respecf.ively, as the nuclear fuelis consumed. Also, we have operating lease commitments net of trust cash receipts of approximately $39 million for the 1999-2003 period, of which approximately $6 million relates to 1999. We recover the cost of nuclear fuel consumed and operating leases through our electric rates.
FirstEnergy signed an agreement in principle with Duquesne Light Company (Duquesne) that would r' in the transfer of 1,436 megawatts owned by Duquesne at five generating plants in exchange for 1,328 megawatts d.
three plants owned by its electric utility operating companies (see " Common Ownership of Generating Facilities"in Note 1), including the Company's 743-megawatt Avon Lake Plant. A final agreement on the exchange of assets, which will be structured as a tax-free transaction to the extent pnssible is being negotiated. The transaction benefits FirstEnergy's utility operating companies by providing exclusive ownership and operating control of all generating assets that are now jointly owned and operated under the Central Area Power Coordination Group agreement.
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 investment in the Shippingport Capital Trust effectively reduces 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.
The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
There- Fair 1999 20M 2001 2002 2003 after Total Value (M'='s in Millions) ]
Investments other than Cash and Cash Equivalents:
Fixed 'omme $ 25 $ 24 $ 15 8 38 8 48 8 416 $ 566 $ 583 Averace interest rate . 7.7% 7.6% 7.8% 7.7% 7.c% 7.4% 7.5%
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Long-term Debt-
- Fixed rate- -. $145 $175 3 57 $228 $115 $2,003 $2,723 $2.960 Average interest rate . 8.8% 7.2% 8.6% 7.7% 7.4% 7.7% 7.7%
Variable rate . $ 160 $ 160 $ 160 Average interest rate 3.4% 3.4% i Short-term Borrowings $ 81 $ 81 $ 81 Avernoe intetest rate.. 55% 55%
Preferred Stock- $ 33 $ 33 $ 81 $ 19 5 1 $ 5 $ 172 $ 184 Averace dividend rate . 9.0% 9.0% 89% 89% 7.4% 7.4% 8.9%
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Outloolc We face many competitive challenges in the years ahead as the electric utility industry undergoes !
significant changes, including regulation and the entrance of more energy suppliers into the marketplace. Retail wheeling, which would allow retail customers to purchase electricity from other energy producers, will be one of those challenges. The FirstEnergy Rate Reduction and Economic Development Plan provides the foundation to position us to l meet the challenges we are facing by significantly reducing fixed costs and lowering rates to a more competitive level. l
, The plan was approved by the PUCO in January 1997, and initially maintains current base electric rates through j December 31,2005. The plan also revised our fuel recovery method '
As part of the regulatory plan, the base rate freeze is to be followed by a $217 million base rate reduction in 2006; interim reductions which began in June 1998 of $3 per month will increase to $5 per month per residential customer by July 1,2001. Total savings of $280 million are anticipated over the term of the plan for our customers. We have committed $70 million for economic development and energy efficiency programs.
We have been authorized by the PUCO, for regulatory accounting purposes, to recognize additional depreciation related to our generating assets and additional amortization of regulatory assets during the regulatory plan period of at least $1.4 billion more than the amounts that would have been recognized if the regulatory plans were not in effect. For regulatory purposes these additional charges will be reflected over the rate plan period. Our regulatory plan ,
does not provide for full recovery of nuclear operations. Accordingly, regulatory assets representing customer l receivables for future income taxes related to nuclear assets of $499 million were written off (5324 million net of income taxes) prior to consummation of the merger since we ceased application of Statement of Financial Accounting Standards No. 71 (SFAS 71).
- Accounting for the Effects of Certain Types of Regulation" for our nuclear operations when implementation of the FirstEnergy regulatory plan became probable.
Based on the current regulatory environment and our regulatory plan, we believe we will continue to be able to bill and collect cost-based rates relating to our nonnuclear operations. As a result, we will continue the application of SFAS 71. However, changes in the regulatory environment appear to be on the horizon for electric utilities in Ohio. As further discussed below, the Ohio legislature is in the discussion stages of restructuring the State's electric utility industry. Although we believe that regulatory changes are possible in 1999, we cannot currently estimate the ultimate impact.
At the consummation of the merger in November 1997, we recognized a fair value purchase accounting l adjustment, which decreased the carrying value of our nuclear assets by approximately $1.7 billion based upon cash ;
flow models. The fair value adjustment to nuclear plant recognized for financial reporting purposes will ultimately satisfy I the asset reduction commitment contained in our regulatory plan. l We continue to actively pursue the enactment of fair legislation calling for deregulation of Ohio's investor-owned electric utility industry. In early 1996, a deregulation proposal was introduced, leading to the creation of a working group to recommend legislation. As requested by legislative leadership, investor-owned utilities introduced a deregulation plan with objectives to (1) treat all major stakeholders in Ohio's electric system fairty; (2) protect public schools and local govemments from revenue loss; and (3) allow utilities an opportunity to recover costs of govemment- ,
mandated investments. The utilities have submitted proposals, which incorporate these objectives and also recognize !
the complexity of restructuring the industry. The overtying objective is to do the job right the first time. Currently, the working group, comprised of legislative leaders, representatives of the electric utility companies and other interested stakeholders are rneeting to discuss and mold these proposals. Most recently, placeholder bills containing statements of principle (that will be replaced by specific proposals as they are agreed upon) have been introduced. Legislative leaders have placed a high priority on enacting a deregulation bill by mid-year.
The Clean Air Act Aswidgwits of 1990, discussed in Note 5, require additional emission reductions by 2000. We are pursuing cost effective compliance strategies for meeting these reduction requirements.
On September 24,1998, the Federal Environmental Protection Agency issued a final rule establishing tighter nitrogen oxide emission requirements for fossil fuel-fired utility boilers in Ohio, Pennsylvania and twenty other
- - eastem states, including the District of Columbia (see " Environmental Matters
- in Note 5). Controls must be in place by May 2003, with required reductions achieved during the five-month summer ozone season (May through September).
The new rule is expected to increase the cost of producing electricity; however, we believe that we are in a better
, position than a number of other utilities to achieve compliance due to our diversified nuclear and hydroelectric generation capacity.
We have been named as a "potentially responsible party" (PRP) for three sites listed on the Superfund National Priorities List and are aware of our potential involvement in the cleanup of several other sites. Allegations that 5
we diernaM of hazardous waste at these sites, and the amount involved are often unsubstantiated and subject to depute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis, if we were held liable for 100% of the cleanup costs of all the sites referred to above, the cost could be as high as $212 million.
However, we believe that the actual cleanup costs will be substantially less than 100% and that most of the other parties ,
involved are financially able to contribute their share. We have accrued a $4.7 million liability as of December 31,1998, based on estimates of the costs of cleanup and our proportonale responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition, cash flows or results of operations. ;
. In connection with FirstEnergy's regulatory plan to reduce fixed c' osts and lower rates, we continue to take steps to restructure our operations. FirstEnergy announced plans to transfer our transmission assets into a new subsidiary, American Transmission Systems, Inc., with the transfer expected to be finalized in 1999. The new subsidiary i.g:% a first stop toward the goal of establishing or becommg part of a larger independent transmission company (TransCo). We believe that a TransCo better addresses the Federal Energy Regulatory Commission's (FERC) stated transmission objectives of providing non-discriminatory service, while providing for streamlined and cost-efficient operation. In working toward the goal of forming a larger regional transmission entity, FirstEnergy, American Electric Power, Virginia Power and Consumers Energy announced in Novenh 1998 that they would prepare a FERC filing during 1999 for such a regional transmission entity, The entity would be designed to meet the goals of reducing transmission costs that result when ii.,_C.;,,g power over several transmission systems, ensuring transmission reliability and providing non-discriminatory access to the transmission grid.
Year 2000 Readiness The Year 2000 issue is the result of computer programs being written using two digits rather than four
, to identify the applicable year. Any of our programs that have date-sensitive software may recognize a date using
- 00" as the year 1900 re: hor than the year 2000. Because so many of our computer functions are date sensitive, this could cause far reaching problems, such as system-wide computer failures and miscalculations, if no remedial action is taken.
We have developed a multi-phase program for Year 2000 compliance that consists of an assessment of our systems and operations that could be affected by the Year 2000 problem; remediation or replacement of noncompliant systems and components, and testing of systems and components following such remediation or replacement. We have focused our Year 2000 review on three areas: centralized system .w;~.;;0ns, noncentralized systems and relationships with third parties (including suppliers as well as end-use customers). Our review of system readiness extends to systems involving customer service, safety, shareholder needs and regulatory obligations.
- We are committed to toldng appropnate actions to eliminate or lessen negative effects of the Year 2000 issue on our operations We have completed an inventory of all computer systems and hardware including equipment with embedded computer chips and have determined which systems need to be converted or replaced to become Year 2000-ready and are in the process of remediating them. Based on our timetable, we expect to have all identified repairs, replacements and upgrades con-A M to achieve Year 2000 readiness by September 1999.
Most of our Year 2000 issues will be resolved through system replacement. Of our major centralized systems, the general lodger system and inventory management, procurement and accounts payable systems were replaced at the end of 1998. Our payroll system was enhanced to be Year 2000 compliant in July 1998. The customer service system is due to be replaced in mid-1999.
We have completed formal communications with most of our key suppliers to delemune the extent to which we are vulnerable to those third parties' failure to resolve their own Year 2000 problems. For suppliers having potenhal compliance problems,'we are developing allemate sources and services in the event such noncomphance occurs. We are also identifying areas requiring higher inventory levels based on compilance uncertainties. There can be no guarantee that the failure of companies to resolve their own Year 2000 issue will not have a matenal adverse ellect on our business, financial condition and results of operations.
We are using both intomal and extemal resources to reprogram and/or replace and test our software for Year 2000 modifications. Of the $32 million total project cost, approximately $26 million will be 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 $6 million will be expensed as locurred. As of December 31,1998, we have spent $19 mil"on for Year 2000 capital projects and had expensed approximately $3 million for Year 2000-related maintenance activities. Our total Year 2000 propect cost, as well as our estimates of the time needed to complete remedial efforts, are based on currently available 6-j
F-I information and do not include the estimated costs'and time associated with the impact of third party Year 2000 issues.
. We believe we are managing the Year 2000 issue in such a way that our customers will not experience any interruption of service. We believe the most likely worst-case scenario from the Year 2000 issue will be
, disruphon in power plant monitoring systems, thereby producing inaccurate data and potential failures in electronic switching mechanisms at transmission Junctions. This would prolong localized outages, as technicians would have to manually activate switches. Such an event could have a material, but currently undeterminable, effect on our financial results. We are developing contingency plans to address the effects of any delay in becoming Year 2000 compliant and expect to have contingency plans completed by June 1999.
The costs of the project and the dates on which we plan to complete the Year 2000 modifications are based on management's best estimates, which were derived from numerous assumptions of future events including the continued availability of certam resources, and otter factors. However, there can be no guarantee that this project will be w-;n d as planned and actual resuns could differ matettany from the estimates. speerfic factors that might cause material differences include but are not hmited to, the avM and cost of tramed personnel, the abihty to locate and correct all relevant computer code, and smier uncertainties.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME 4
For the Year Forthe Year Ended Ended -
December 31, Nov. 8 - Jan.1 - December 31, 1998 Dec.31.1997 Nov. 7.1997 1996 (in thousands)
- OPERATING REVENUES .. . . $ 1.782.376 $253.96} $1.529 014 $1.789.961 OPERATING EXPENSES AND TAXES:
Fuel and purchased power . 435.752 53239 368.243 418.145 Nudear operating costs 97.914 16.791 85.207 89.514 Other operating costs 335.621 57.852 286.384 381.976 Total operation and maintenance expenses 869.287 127.882 739.834 889.635 Provision for depreciation and arnortization 224.430 31.978 211.827 244.615 Generaltaxes _ . 221,077 33.912 194,400 229.856 income taxes . . . . - 98.680 _,,12,$g2 75.621 67.235 Total operating expenses and taxes 1 413.474 E 4m 1.221.682 1.431.341 OPERATING INCOME 368,902 49.502 307,332 358.620 OTHER INCOME (EXPENSE) .. 25.393 4.572 f2.476) (2.089)
INCOME BEFORE NET INTEREST CHARGES 394.295 54.074 304.856 356.531 NETINTEREST CHARGES:
Interest on long-term debt . 234.795 35.300 197.323 229,491 Allowance for borrowed funds used during construction . (2.079) (631) (1.928) (2.110)
Other interest expense . --
(3 312) 115 14.270 12.597 Net interest charges -
229.404 . 34.784 209.665 239.978 INCOME BEFORE EXTRAORDINARY ITEM. 164.891 19,290 95,191 116.553 EXTRAORDINARY ITEM (NET OF INCOME TAXES)(Note 1)- - - (324.438) -
NET INCOME (LOSS) . 164.891 19,290 (229.247) 116.553 PREFERRED STOCK DIVIDEND REQUIREMENTS- . 24.794 - 45.029 38.743 EARNINGS (LOSS) ON COMMON STOCK $ 140.097 g 5 (274.276) $ 77.810 The accornpanying Notes to Consolidated Fhancial Staternents are an integral part of these statements, s
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l THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS
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At December 31, 1998 1997
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ASSETS UTILITY PLANT:
In service . . . $4.648.725 $4.578.649 L- - ^ ~nulated provision for depredacon - 1.631.974 1.470.084 3.016.751 3.108.565 Construchon work in progress-Electne plant .- . - . . . 42,428 41.261 Nuclear fuel -
14.864 6.833 57,292 48.094 3.074.043 .3.156.659 OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2) . 543.161 575.084 Nudear plant decommisstoning trusts . 125,050 105.334 Other 21.059 21.482 689.270 701.900 CURRENT ASSETS:
Cash and cash equivalents . 19.526 33.775 Remivables-Customers . 16.588 29.759 i Assocated mmpanses 15.636 8,695 l Other. . 142,834 98,077 Notes recolvable from associated companies- 53,509 -
Materials and supplies, at average cost- ,
Owned . . .. . 38.213 47,489 i Under consignment . . 43.620 25,411 Prepayments and other . -
58.342 57.763 388.268 300.% 9 l l
DEFERRED CHARGES: l Regulatory assets 555,925 579,711 l Goodwiu... - -. . 1,471.563 1.552.483 Property taxes . -. . 126.464 125,204 Other . . . . .. 12.650 23 358 2.166.602 2.280.756 56 318.183 56 440.284 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitlization):
Common stockholder's equity .. $1.008.238 $ 950,904 Preferred stock-Not subject to mandatory redemption.. .. .. 238.325 238.325 Subject to mandatory redempnon 149.710 183.174 Lcog-term debt -
. 2.888.202 3.189,590 4.284.475 4.561.993 CURRENT LIABILITIES:
Currency payable long-term debt and preferred stock - 208.050 121,965 Accounts payable-Assodated companies: 47.680 56,109 Other .
92.976 90.737 Notes payable to associated companies 80.618 56.802 Accrued taxes 192,359 194,394 Accued interest 66.685 67.896 Other ... 37.278 52.297
- a. 725.646 640.200 DEFERRED CREDITS:
Accumulated deferred income taxes 524,285 496.437
, AcaJmulated deferred investment tax credits 90.946 96,131 Pensions and other postrenrement benefits 217.719 196,642 Other _... 475.112 446.881 1.308.062 1.238.091 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 2 and 5 ) - "
56.318.183 56.440.284 The accompanying Notes to Consohdated Finandal Statements are an integral part of these balance sheets. 9
I THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOUDATED STATEMENTS OF CAPITALIZATION At December 31. 1998 1997 '
(Donars in shousanels, except per share amounts) .
CotstAON STOCKHOLDER'S EQUITY:
Common stock without per value, authorized 105.000.000 shares-
- 79,590,689 shares outstandinD . ... .. - . . 5 931,962 8 931.614 Retained eamings (Note 3A) ._ 76.276 19.290 Total common stockholder's equity .. ~. 1.008.238 950.904 Number of Shares Optional Outstandinn Redemotion Price 19.3g Igel Per Share Accreeste PREFERRED STOCK (Note 3C):
Cumulative, without par value-Authonzod 4,000.000 shares Not Subsect to Mandatory Redempeon:
s 7.40 Series A . . . .. 500,000 500,000 5 101.00 $ 50,500 50,000 50.000
- 8 7.56 Sortes 8 .. 450,000 450,000 102.26 - 46.017 45.071 45.071 Adjustable Series L.~ . .. 474,000 474.000 100.00 47,400 46.404 46.404
$42.40 Series T . ....-. . 200.000 200.000 500.00 M 96.850 3 8,39 Total not subsect to mandatory redemption. g ,1gg4ggg ig4M1,I 238.325 238.325 Subject to Mandatory Redemp60n (Note 30):
$ 7.35 Series C. 100.000 110,000 101.00 $ 10.100 10.110 11,110
$88.00 Series E .... . 6,000 9.000 1.003.83 6,023 6.000 9.000
$91.50 Series Q .. .. . . - 32,144 42.858 1,000.00 32.144 32.144 42.858
$88.00 Senes R 50,000 50,000 - - 55,000 55,000
$90.00 Series S . . 74,000 74,000 - - 79.920 79.920 Redempton within one year . (33.464) (14.714)
Total subrect to mandatory redempton 262.144 _lg5mggg )_4g2g7 149.710 183.174 LONG.TERed DEST (Note 3E):
First mortgage bonds:
7.625% due 2002 195,000 195,000 7.375% due 2003 - - . 100.000 100.000 8.750% due 2005.- ,. - . . . . . -
- 75,000 9.500% due 2005 . 300,000 300,000 6.880% due 2008 - . . . . . 125.000 -
8.375% due 2011 . . . . _ . . . . . - 125,000 8.375% due 2012 . -
- - 75.000 9.000% due 2023 .. _ . . 150.000 150.000 Totalfirstmortgage bonds . .. 870.000 1.020.000 Unsecured notes:
6.700% dus 2006 . .
- 19.500 5.700% due 2006_ . ... .
- 7,300 6.700% due 2011 _ ..
5.500 5.875% due 2012 . . .. _ ..
- 14.300 Total unsecured notes .. . _
- 46.600 10
l THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
At December 31. 1998 1997 LONG. TERM DEST:(Cont.)
Secured notes:
8.150% due 1998- -
7.500 8.160% due 1998 . .. -
5.000 8.170% due 1998 _ -
11.000 8.260% due 1998. .. -
2.500 8.330% due 1998 -
25.000 8.870% due 1998.. - . -
10.000 9.000% due 1998 . . -
5.000 7.000% due 1999 2009 . . . . . . 1.880 1.910 7.250% due 1999 .... 12,000 12.000 7.670% due 1999. 3.000 3,000 7.770% due 1999 17.000 17.000 7.850% due 1999 . 25,000 25.000 8.290% due 1999 -
10.000 10.000 9.250% due 1999 52.500 52.500 9.300% due 1999. . 25.000 25,000 7.190% due 2000-- . . 175.000 175.000 7.420% due 2001 .... . . 10.000 10.000
. 8.540% due 2001 . 3.000 3.000 8.550% due 2001- . 5.000 5.000 8.560% due 2001. . .. -- . 3.500 3,500 8.680% due 2001 - - . 15.000 15,000 9.050% due 2001- 5.000 5.000 9.200% due 2001 . . . 15.000 15.000 7.850% due 2002 . ... . . . . . . 5.000 5.000 8.130% due 2002 28.000 28.000 7.750% due 2003 .- 15.000 15.000 7.670% due 2004. .._. . . - 280.000 280.000 7.130% due 2007 .. . .. 120,000 120.000 7.430% due 2009- . - 150.000 150.000 6.000% dus 2011' ...
- 5,650 6.000% due 2011* -
1.700 8.000% due 2013 . 78.700 78.700 3.278% due 2015' . . . . . . .. 39.835 39,835 6.000% due 2017* . -
1.285 7.880% due 2017 .. .. . 300.000 300.000 3.060% due 2018* _. m 72.795 72.795 4.100% due 2020' . - ~. 47.500 47.500 6.000% due 2020' . ._
- 40.900 6.000% due 2020* -
9.100 6.000% due 2020. . . . . 82.560 62.560 6.100% due 2020 m. . . 70.500 70.500 9.520% due 2021 . 7.500 7.500 6.850% due 2023 _ 30.000 30.000 8.000% due 2023 . .. 73.800 73.800 7.625% due 2025- .. . . 53.900 53.900 7.700% due 2025 . . . . . . . .
.~ ~~.~ . 43,800 43.800 7.750% due 2025 . 45.150 45.150 5.375% due 2028 ~ . . . 5,993 -
4.400% due 2030 ..
_- 23.255 -
4.600% due 2030 . . . - .... . 81.640 -
Total secured notes ... .
2.012.808 2.026.585 Capitallease obligations (Note 2) -.
, 94.568 98.504 Net unamortized premium on debt 85.412 105.152 Long. term debt due within one year -
(174.586) (107.251)
, Totallon9-term debt ~ 2.888.202 1 189.590 TOTAL CAPITALIZATION .
$4.284.475 14_,30.1, 29.3
- Denotes variable rate issue with December 31,1998 interest rate shown for December 31,1998 balances and December 31,1997 Interest rate for lasues with only December 31,1997 balances.
The accompanyin9 Notes to Consolidated Financial Statements are an integral part of these statements.
11
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'O dQUITY Comprehensive Other Retained .
Income (Loss) Number Carrying Paid-in Earnings (Note 3B) of Shares Value Capital (Defictt)
(Dollars in mousands)
Balance, January 1,1996- 79,590,389 $1.241.284 $ 78,624 $(193.146) .
Net income -
$ 116.553 116.553 Redassification of $90.00 Series S preferred stad redemption gain -- (iii) 111 Unrealized loss on securtties (6)
Gain on redemption of Adjustable Series L preferred stock _. 725 Carrying value adjustments for preferred stock redemptions 114 Cash dividends on preferred stock.., .
(38,734)
Cash dividends on common stod.. . . (160,816)
Other, primartly preferred stock r e ,a4,en exoenses...... (315)
Balance December 31,1996. . ... -
79,590,689 1,241,287 79,454 (276,458)
Net (loss), -
$f229 247) (229,247)
Equity contributions from parent 4,500 Carrying value ad}ustments for preferred stod redemptions- 25 Cash dividends on preferred stod (35.848)
Cash dividends on common s*~* (123,602)
Other, primarily preferred stod redemption expense.s . . (232)
Purchase accounting fair value adjustment ... . (309.698) (83,954) 665,387 Net income ... $ 19 290 19.290 Eaiance, December 31,1997. . . . . . . . . . . . . . . . . 79,590.689 931,614 - 19,290 Purchase accounting fair value adjustment 348 Netincome $ 164.891 164,891 Cash dividends on preferred stock- (21,947)
Cash dividends on common stock.. r85.958)
Balance. Ocamber 31.1998 . 79 590.689 5 931 962 5 - 5 76.276 CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemotion
'-Number Carrying Number Carrying of Shares Value of Shares Value (Dollars In housands)
Balance, January 1,1996... .- .. 1,650,000 $240,871 633,286 $245,134 Redemptions.
Adjustable Series L (26,000) (2,546)
$ 7.35 Series C (10,000) (1,000)
$88.00 Senes E (3,000) (3,000)
$9.125 Series N (150,000) (14,794)
$91.50 Series O. ............. (10.714) (10.714)
Batana, December 31,1996 1,624,000 238,325 459,572 215,626 Redemptions.
8 7.35 Series C . (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$9.125 Series N (150.000) (14,794)
$91.50 Series Q (10,714) (10,714)
Purdase accounting fair value adjustment-S 7.35 Series C 110
$88.00 Series R 5,000
$90.00 Series S .............. 6.660 Balance, December 31,1997 1,624,000 238,325 285,858 197,888 Redemptions- .
S 7.35 Series C (10,000) (1,000)
$88.00 Series E -- (3,000) (3,000)
$91.50 Series O ........... ... (10.714) (10.714)
Balance December 31.1998.. 1.624 000 5238 325 262.144 5183.174 g The accompanying Notes to Consolidated Finandal Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year For the Year Ended Ended December 31, Nov. 8 - Jan.1 - December 31, 1998 Dec.31.1997 Nov. 7.1997 1996 (In thousands)
CASH FLOWS FROM OPERATING ACTMTIES:
Net income (Loss) $164,891 $ 19,290 $(229.247) $ 116,553 Adjustments to remndle twt income to net cash from operaung activities:
Provision for depredation and amortization 224,430 31.978 211,827 244,615 Nudear fuel and lease amortization. 35,361 7,393 42,577 45.987 Otner amor11zation . (12,677) - - -
Deferred income taxes, net. 22.949 7,723 (126.693) 24,973 investment tax credits, not .. (5,185) (822) (6.670) (7.992)
Allowana for equity funds used dunng construction- -
(140) (1.647) (2,014)
Extraordinery item. - -
499.135 -
Receivables . (38,527) 51,213 (3,974) 586 Net promeds from accounts receivable securitization .. - - -
64.891 Matsrials and supplies (8.933) (3.922) 6,363 25,589 Acmunts payable . 20.180 (777) (7,938) (6.344)
Other -
.. .. f53 433) 18.839 (2.566) 10.992 Net cash provided from operating activities- 349.056 130.775 381.167 517.836 CASH FLOWS FROM FINANCING ACTMTIES:
New Fmndng-Long. term debt 232.919 - 1,176,781 (307)
Ohio Schools Coundl prepayment program .. 116,598 - - -
Short-term Micmngs, not 23,816 703 - 106,618 Redemptions and Repayments-Preferred stod( _ 14,714 - 29,714 31.528 Long. term debt. . 488.610 43,500 701.843 310,177 Short. term liq, not.. - .
- - 55,519 -
Dividend Payments-Common stock- -
. 85,958 34,785 88,816 160,816 Preferred sM- . 34.841 . 7.191 29.311 . 39.325 Net cash provided from (used for) finandng adivities '?50.790) (84.773) 271.578 (435.535)
CASH FLOWS FROM INVESTING ACTMTIES:
Property addisons 72,130 17,943 104,230 105.588 Loans to assodated wnv.nb- 53,509 - - -
Capitaltrustinwstments -. -
(31.923) 16,248 558,836 -
Other. _ . 18.799 f4.288) 2.276 _ 1,1,2ft.Q Net cash used for investing activities 112.515 29.903 665.342 121.798 Net increase (decrease) in cash and cash equivalents . (14.249) 16.099 (12.597) (39,497)
Cash and cash equivalents at beginning of perm 33.775 17.676 30.273 69.770 Cash and cash equivalents at end of period. $ 19.526 1,,,J2J_7j $ 17.676 1 22,2.7.]
SUPPLEMENTAL CASH FLOWS INFORMATION: i Cash Paid During the Period- i
. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
I l
13
T THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES Forthe Year For the Year Ended Ended .
December 31, Nov. 8 - Jan.1 - December 31, -
1998 Doc.31.1997 Nov. 7.1997 1996 (in thousands)
GENERAL TAXES:
Real and personal property . _- $ 130.642 $ 17.707 $ 114.393 $ 132.582 State 9ross remipts 78.344 13.302 65.966 78.109 Sodalsecurtty and unemployment . 9.029 1.548 6.296 9,127 Other _, 2,g62 1.355 7.745 10.038 Total general taxes. . $ 221.077 $ 33.912 $ 194.400 M PROVISION FOR INCOME TAXES:
Currently payatWe-Federal --
$ 90.690 $ 6.969 5 37.605 5 44,147 State * . .. - - - 2.158 159 - -
92.848 7.128 37.605 44.147 Deferred, net-Federal.. .. . . . 22.743 7.617 (126,693) 24.973 State * .. 206 106 - -
__22.949 7.723 _1126.693) 24 973 Investment tax credit amortization (5.185) (822) (6.670) (7.222)
Total provision forincome taxes $ 110.612 $ 14.029 $ (95.758) $ 61.128 INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES:
Operating income $ 98.680 $ 10,689 8 75.621 3 67.235 Other income ... ... 11.932 3.340 3.318 (6.107)
Extraordinaryitem - - (174.697) -
Total provision forincome taxes .. $ 110.612 $ 14 029 $ (95.758) $ 61.128 RECONCILIATION OF FEDERAL INCOME TAX tiXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes. $ 33.319 S f325.005) $ 177.681 Federal income tax expense at statutory rate .
5 11.562 5(113.752) 5 62.188 increases (reductions)in taxes resulting from.
Amortization of investment tax aedits (5,186) (822) (6.670) (7.992)
Depredation m
- - 14,780 7.853
}
l Amortization of tax regulatory assets . ... . 7.038 1.170 -
Amortization 9of aodwill . . . 13.447 2.015 -
Other, net (1.113) 4 9.884 (921)
Total provision forincome taxes $ 110.612 $ 14 029 $ (95.758) $ 61.128 ACCUMULATED DEFERRED INCOi4E TAXES AT DECEMBER 31 :
Property basis differences. $ 672.283 $ 676.853 $ 1.482.000 Deferred nudear expense 132.819 133.281 134.000 Defemed sale ' nd leaseback ooets . (113.884) (118.611) (121.000)
Urew ig.-d invoetment tax aedits . (40.241) (42.743) (95.000)
Unused attemative minirnum tax aedits - (124.459) (133.442) (173.733)
Other . . . (2.232) (18.901) 79 334 Net deferred incarne tax liability. . $_$24_20$ $ 496.437 $ 1.305 601
- For periods prior to November 8.1997, state income taxes are induded in the General Taxes section above. These amounts are not material and no restatement was made.
The acxmmpanying Notes to Consolidated Financial Statements are an integral part of these statements.
14
i NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES:
1 .
l The consolidated financial statements include The Cleveland Electric illuminating Company (Company) i and its wholly owned subsidiary, Centerior Funding Corporation (Centerior Funding). The subsidiary was formed in 1995
, to serve as the transferor in connection with an accounts receivable securitization completed in 1996. All significant
+ intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp.
, (FirstEnergy). Prior to the merger in November 1997 (see Note 7), the Company and The Toledo Edison Company (TE)
I were the principal operating subsidiaries of Centerior Energy Corporation (Centerior). The merger was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles, and the applicable effects were reflected on the separate financial statements of Centerior's direct subsidiaries as of the merger l
date. Accordingly, the post-merger financial statements reflect a new basis of accounting and pre-merger period and post-merger period financial results (separated by a heavy black line) are presented. The Company follows the accounting policies and practices prescribed by the Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with generally accepted accounting principles requires management to make periodic estirnates 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 Company's principal business is providing electric service to customers in northeastem Ohio. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year.
Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables at December 31,1998 or 1997, with respect to any particular segment of the Company's customers, in May 1996, the Company and TE began to sell on a daily basis substantially all of their retail customer ,
accounts receivable to Centerior Funding under an asset-backed securitization agreement which expires in 2001, in l July 1996, Centerior Funding completed a public sale of $150 million of receivables-backed investor certificates in a transaction that qualified for sale accounting treatment.
REGULATORY Pl.AN-l FirstEnergy's Rate Reduction and Economic Development Plan for the Company was approved in l l January 1997, to become effective upon consummation of the merger. The regulatory plan initially maintains current i base electric rates for the Company through December 31, 2005. At the end of the regulatory plan period, the
! Company's base rates will be reduced by $217 million (approximately 15 percent below current levels). The regulatory l plan also revised the Company's fuel cost recovery method. The Company formerly recovered fuel-related costs not I otherwise included in base rates from retail customers through a separate energy rate. In accordance with the regulatory ;
plan, the Company's fuel rate will be frozen through the regulatory plan period, subject to limited periodic adjustments. 1 As part of the regulatory plan, transi' ion rate credits were implemented for customers, which are expected to reduce operating revenues for the Company by appdi,Aly $280 million during the regulatory plan period.
All of the Company's regulatory assets related to its nonnuclear operations are being recovered under provisions of the regulatory plan (see
- Regulatory Assets"). The Company recognized a fair value purchase accounting adjustment to reduce nuclear plant by $1.71 b!Ilior$ in connection with the FirstEnergy merger (see Note 7); that fair value adjustment recognized for financial reporfng purposes will ultimately satisfy the $1.4 billion asset reouction corrmtment contained in the regubtory plan. For regulatory purposes, the Company will recognize the $1.4 billion of accelerated amortization over the regulatory plan period.
Application of Statement of Financial Accounting Standards (SFAS) No. 71,
- Accounting for the Effects of Certain Types of Regulation" (SFAS 71), was discontinued in 1997 with respect to the Company's nuclear operations.
l The Company's net assets included in utility plant relating to the operations for which the application of SFAS 71 was e discontinued were $1,064 million as of December 31,1998.
15 L
UTIUTY Pl. ANT AND DEPRECIATION.
Utsty pient renects the original cost of construchon (except for the Company's nuclear generating units which were adjusted to fair venue in 1997), including payroH and related costs such as taxes, employee benents, administrative and general costs, and interest costs.
~ The Company provides for depreciabon on a straight-line basis at vanous rates over the estmaled lives of '
property included in plant in service. The annualized composite rate was approxwnstely 3.4% (reRectmg the nuclear .
- asset fair value adjustment discussed above) and 2.8% for 1998 and the post-merger 1997 period, respectively, in its Apr81996 rate order, the PUCO approved depreciabon rates for the Company of 2.88% for nuclear property and 3.23%
for nonnucieer property, Annual depreciation expense includes approximately $11.7 milhon for future decommissioning costs apfe.hsa to the Company's ownership interests in three nuclear generating units. The Company's share of the future obligation to decommission these units is approximately $432 minion in current donars and (using a 4.0% escalabon rate) approximately $1.1 bulion in future doNars.The ashmated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are sxpected to begin in 2016, '
when actual d.w.is,;.Anas work begins. The Company has recovered approximately $110 rnHlion for C+:4... - As through its electric rates from customers through December 31,199',. If the actual costs of C+x ' ^--#s the units exceed the funds accumulated from investing amounts reraered from customers, the Company expects that additional amount to be '
recoverable from its costomers. The Company has approximately $125.0 rmllion invested in extemal decommesiomng ..
trust funds as of December 31,1998. Eamings on these funds are reswested with a w,i rn, Caw increase to the C+- ... 3-#s liabiuty. The Company has also recognized an estimated liability of approximately $10.1 miluon at December 31,1998 reisted to decontaminsbon and decommissemng of nuclear onrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992.
The Financial Accounting Standards Board (FASS) issued a proposed accounting standard for nuclear C+ - ... -is costs in 1996. If the standard is adopted as proposed: (1) annual provisions for decommissionmg .
could increase; (2) the not present value of eshmated decorsnissioning costs could be recorded as a Babihty; and (3) .
Income from the extemal decommissoning 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 10 long-hved assets. A revoed proposal may be issued by the FASB in 1999.
. 'COlalAON OWNERSHIP OF GENERATING FACILITIES.
The Company, TE, Duquesne Light Company (Duquesne), Ohio Edison Company (OE) and its whouy owned anh=Hary, Pennsylvania Power Company (Penn), consutute the Central Area Power Coordinsbon Group (CAPCO). The CAPCO Companies own and/or lease, as tenants in common, various power generahng faciubes. Each
. of the companies is obligated to pay a share of the costs associated with any joindy owned faclNty in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned faculties is included in the corresponding operating expenses on the Consohdated Statements of income. The amounts reflected on the Consohdated Balance Sheet unoer utility plant at December 31,1998 include the following utuny Acoumuisted conservation ownershipt Plant Provision for Work in I.aesehold a __
u.a. In L. .-: e- ._ inansent prs mRNons)
Bruce Menensid Units 1,2 and 3 8 63.8 5 23.1 81.8 19.92%
Beever Vasey Unit 2 341.5 16.5 - 1.0 24.47 %
Davis.8 esse 201.9 - 4.1 51.38 %
Perry . 546.6 24.9 7.6 31.11 %
Easuske Unit 5 160.5 116.8 0.7 68.80 %
Sarwm 64.3 - 25.4 OM 80.00 %
Taial $ 1.378.6 RSam 7 S15.3 ,
The Bruca Mansfleid Plant is being leased through a sale and lamanhack transaction (see Note 2) and the '
aboveseisted amounts represent construction expenditures subsequent to the transaction.
The Senocs Unit is currently jointly owned by the Company and a non-CAPCO company. FirstEnergy has agreed to purchase the remaining 20% share in 1999.
16 b
.J On October 15, igg 6, F.;C vi announced that R signed an agreement in pnnciple with Duquesne that would resuR in the transfer of 1,436 megawans owned by Duquesne at eight CAPCO generating units in exchange for
- 1,328 megewous at three non-CAPCO power plants owned by the Company, OE and Penn. As part of this exchange,
, the Company will transfer the 743-megawatt Avon Lake Plant to Duquesne A dennitive agreement on the exchange of assets, which wiH be structured as a tax-free transaction to the extent possible, wlH provide FirstEnergy's utiHty operating companies with excluseve ownership and operating control of au CAPCO generating units. Duquesne will fund C+s 1 '- ,;,,, costs equal to its percentage interest in the three nuclear generating units to be transferred. The asset
. transfer is awpared to take twelve to aghteen months to close.
' NUCLEAR FUEL.
The Company leases its nuclear fuel 'and pays for the fuel as it is consumed (see Note 2). The Company amortizes the cost of nuclear fuel based on the rate of consumption. The Company's electric rates include amounts for the future rearvaal of spent nuclear fuel based upon the payments to the DOE.
INCOME TAXES-Detalis of the total provision for income taxes are shown on the Consoldated Statements of Taxes.
Deferred income taxes result from timine differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when usHized, are being amortized over the recovery period of the reisted propedy. The liability method is used to account for deferred income taxes. Deferred income tax liabilities reisted to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the hahilman are expected to be paid. Allemative minimum tax credits of $124 mulion, which may be carried forward indenneoly, are available to reduce future federal income taxes. Since the Company became a wholly owned subsidiary of I,r4 vy on November 8, igg 7, the Company is included in FirstEnergy's consolidated federal income tax retum.
The cor=ahti=8 art tax liabiHty is allocated on a " stand-alone" company basis, with the Company recognizing any tax losses or credNs it contributed to the consolidated retum.
RETIREMENT BENEFITS-Centerior had sponsored joindy with the Company, TE and Centerior Service Company (Service Company) a r,c,,,-,,:,;t,ulory pension plan (Centerior Pension Plan) which covered an employee groups. Upon rebrement, employees receive a monthly pension genannHy based on the length of service in igg 8, the Centerior Pension Plan was merged into the FirstEnergy pension plans, in connechon with the OE-Centerior merger, the Company recorded fair value purchase accounting adjustments to recognize the not gain, prior service, cost and not transition asset (obligation) associated with the pension and postratirement benent plans. The assets of the pension
. plans conost primertly of common stocks, United States govemment bonds and corporate bonds.
The Company provides a minimum amount of noncontributory are insurance to retred employees in addition to opbonel coreibutory insurance. Heenh care benents, which include owten employee ded-ahia= and copsyments, are also available to retired employees, their dependents and, under certain circumstances, their survivors The Company pays insurance premiums to cover a portion of these benents in excess of set limits; aH amounts up to the limits are paid by the Company. The Company recognizes the arpae* art cost of providing other postrotrement beneAts to employees and their benenciaries and covwed dependents from the time employees are hired unel they become eligible to receive those benents.
4 l
17 j l
I
A The logowing sets forth the funded etstus of the FirstEnergy plans in 1998 and the former Centerior plans in 1997 and amounto recognized on the Consolidated Bolence Sheets as of December 31:
Other Pennien Rename Pontratirement BeneAls 1ees tee 7 ines 1e07 .
(in mtitions)
Change in benent otsgation:
Benent otWooson as of.lenuary 1* . . . .. $1,327.5 8 395.0 8 534.1 8 211.9
- Service cost . . . .- 25.0 13.4 7.5 2.3 .
interest oost _.. . . . . _. .~ _ - 92.5 31.5 37.s .1s.3 Plan amendment . . . .. . . ~ 44.3 7.1 40.1 -
Early roerement program expense . . - 27.8 - -
Actuariellose - ... .- . - . . . . ~ ~ . 101.6' '74.8 10.7 51.9
": - "" naart ..
. fan A) (18.2) (28.7) - f15.9)
BanaAt % as of rw=.nhar 31.. 1.500.1 533.4 601.3 288.5 Change in plan assets: . . .
Fair value of plan assete se of.lenuary 1* .. 1.542.5 420.8 2.8 -
Actual retum on plan asset ..... . 231.3 '57.3 0.7 -
Company contribu90n . .. . . . '- .- 0.4 -
BeneAls neid (90.8) (18.2) - -
Fair u=" of namn - - as of r - - - - 31. . 1 aa3.0 461.9 3.9 -
- Funded status of pion *. . . . . . . 182.9 (71.5) (597.4) -- (206.5) unrecognized actueriallose (goin) . (110.8) 3.0 30.6 -
unrecognised prior service cost . . . . . . . 63.0 - 27.4 -
y, _- - - - ' nd.t ^ -- =. 2 " - T = . f (18.0) - 129.3 -
-- < farrruatin banellt ==* . '$ 117.1 $ 188.5) Sl410.1) et9eA A)
Assumptione used as of December 31:
Diecount rete . 7.00 % 7.25% 7.00% 7.25 %
Expected long.lerm retum on pien asset. _. 10.25 % 10.00 % 10.25 % 10.00 %
Mate of compensanon increase. .. 4.00 % 4.00 % 4.00 % 4.00 %
- 1998 beginning belances represente 1996 merger of Centerior and OE piene into FirelEnergy piens.
. The Consolidated Balance Sheet claeolhostion of Pensions and Other Poetratirement Benents at December 31,1998 and 1997 includes the Company's share of the not pension Bability of $47.7 milhon and $49.2.
million, respectively; and the Company's ehere of the accrued poetretirement liability of $170.0 rnilhon and $149.5 million, i-E+M/.
Not pension and other postratirement beneAt costs for the three years ended December 31,1998 (FirstEnergy plans in 1998 and Centador plans in 1997 and 1996) were computed as fogows-Olhar Poetrolerement maname 19 B7 11 87 Nov. S. Jan.1 Nov. 8- Jan.1 itse - Dae. 31 Nov. 7 1ess itse Dec.31 Nov. 7 9est On anNone)
Servios cost.. . . 8 25.0 " $ 2.3 8 11.1 8 12.6 8 7.5 80.5 81.8 82.1 Interest cost m 92.5 6.1 26.4 ,27.9 37.6 2.8 13.5 17.8 Expected retum on pien esset .
(152.7) (7.7) (3s.0) (43.0) (0.3)
Amerlisellon of ironelgon oldgelion
' (seest) .. . . . . (8.0) -
(3.0) 13.5) 9.2 - 6.4 7.5 Amortiselion of prior servios cost.-. 2.3 - 1.1 1.3 (0.8) - - -
Recognized not actuerial lose (goin). (2.6) -
(0.5) (2.7) - -
(0.9) voluntary eeny remrement progrom
- 22.0 4.8 - - ~- - -
Nat _. .".: enat .. $ 143.5) $23 7 $ 0.9 8 f7 4) S 53.2 S 3.3 $ 20.8 $27.4 Gompany's enere or total plan
- masa $ (2 7) $18.5 8 r2 E) $ f5 0) $ 14 5 S 2.6 l $ 11.4 S18 4 18 f
The FirstEnergy plans' health care trend rate assumption is 5.5% in the first year gradually decreasmg to 4.0% for the year 2006 and later. Assumed heelsh care cost trend rates have a signiRcant effect on the amounts reported for the health care plan. An increase in the health care trend rate assumption by one percentage point would
., increses the total service and interest cost components by $4.0 minion and the postratirement benefit obligation by
$88.1 miHion. A decroses in the same assumption by one percentage point would decrease the total service and interest cost components by $3.2 million and the postratirement benent obligation by $55.2 million.
, TRANSACTIONS WITH AFFilJATED COMPANIES-l Operating revenues, operating expenses and interest charges include amounts for transachons with anilleted comperwes in the ordinary course of buemess operations The Company's transactions with TE and the other F;i.;T.,wvy operaung subsidiarios (OE and Penn)
, from the November 8,1997 merger dele are primar#y for firm power, interchange power, transmission line rentals and I joiney owned power plant operations and construchon (see Note 7). Beginning in May 1996, Centerior Fundmg began serving as the transferor in connection with the accounts receivable securtlization for the Company and TE.
The Service Company (formerly a wholly owned = Mary of Centerior and now a whoHy owned l = Wary of FirstEnergy) provided support services at cost to the Company and other affiliated companies. The Sennce l Company bHied the Company $80.6 minion, $34.1 miluon, $130.8 minion and $148.6 minion in 1998, the November 8-December 31,1997 period, the January 1-November 7,1997 period and 1996, respectively, for such services.
Fuel and purchased power exponess on the Consolidated Statements of income include the cost of power i purchased from TE of $104.7 miHion, $17.7 milhon, $98.5 miHion and $105.0 million in 1998, the November 8-l December 31,1997 period, the January 1-November 7,1997 period and 1996, respecovely, SUPPLEMENTAL CASH FLOWS INFORMATION.
All temporary cash investments purchased wNh an initial maturity of three months or less are reported as cash equivalents on the Coneoudsted Balance Sheets. The Company reRects temporary cash investments at cost.
I which approximates their fair market value. Noncash financmg and investmg activibes included capital lease transactions amounting to $32 mlbion, $3 mHlion, $13 mNilon and $37 milhon in 1998, the November 8-December 31, 1997 penod, the January 1-November 7,1997 period and 1996, i-E+_"di.
AH bonowings with initial maturides of less than one year are deRned as financial instruments under generapy accepted accounting pnnciples and are reported on the Coneohdated Balance Sheets at cost, which approximates their fair market value. The foHowing sets forth the approximate fair value and reisted canymg amounts of all other long-term debt, prefened stock subject to mandatory rNiemption and investments other than cash and cash
=~;iii,;. as of December 31:
inas 1es7 Corrying Fair Canying Fair v"- va- va- Vah =
pre manone)
Lane. term debt __ ' $2.883 $3.120 $3.003 53.238 Profaned seock _ 5.183 8 184 5 198 $ 198 investments olher tien cash aid conh equivalente ,
~ Debtsecurtues
.(Meeuring in more then 10 years) 8 543 $ 533 $ 547 8 553 !
As ashar .. 135 138 io5 1o4 S 878 S 889 S 652 1 657 The canying values of long-term debt and proformd stock autyct to mandatory redempbon wwe adjusted to fair value in conneeson wHh the OE-Centerior merger and renect the present value v the cash outRows relebng to
- a. those securWes bened on the cunent can price, the yield to maturity or the yield to can, as deemed appropriate at the and of each mopecove year. The yields assumed wwe bened on securWes with simuar charachens6cs oMered by a corporsson wnh crust rennes simmer to the Company's raungs.
The fair value of investments othw than cash and cash equivalents represent cost (which approximates ,
fair value) or the present value of the cash innows based on the yield to maturity. The yields assumed were based on - )
financial instruments wnh simmer characterishes and terms. Investments othw than cash and cash equivalents include C+7 ,,, , _
,,,4 trusts investments UnresRzed gains and losses apphcable to the +' x mir-,;is trusts have been l 19 l
recognized in the trust investments with a corresponding change to the decommissioning liability. The debt securities referred to above are in the held-to-maturity category. The Company has no securities held for trading purposes.
REGUI.ATORY ASSETS. ,
The Company recognizes, as regulatory assets, costs which the FERC and PUCO 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 related to nonnuclear operations are being recovered from customers under the ',
Company's regulatory plan. Based on the regulatory plan, at this time, the Company believes it will continue to be able to bill and collect cost-based rates (with the exception of the Company's nuclear operations as discussed below);
accordingly, it is appropriate that the Company continues the application of SFAS 71 in the foreseeable future for its nonnuclear operations.
l The Company discontinued the application of SFAS 71 for its nuclear operations in October 1997 when implementation of the regulatory plan became probable. The regulatory plan does not provide fnr full recovery of the Company's nuclear operations. In accordance with SFAS No.101, " Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS 71,* the Company was required to remove from its balance sheet all regulatory assets and liabilities related to the portion of its business for which SFAS 71 was discontinued and to assess all other assets for impairment. Regulatory assets attributable to nuclear operations of $499.1 million ($324.4 million after taxes) were written off as an extraordinary item in October 1997. The regulatory assets attributable to nuclear operations written off represent the net amounts due from customers for future federal income taxes when the taxes become payable, which, under the regulatory plan, are no longer recoverable from customers. The remainder of the Company's business continues to comply with the provisions of SFAS 71. All remaining regulatory assets will continue to be
' recovered through rates set for the nonnuclear portion of the Company's business. For financial reporting purposes, the net book value of the nuclear generating units was not impaired as a result of the regulatory plan.
Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
1998 1997 Qn mHHons)
Nuclear unit expenses 5 298.0 $ 309.0 Customer receivables for future inmme taxes 13.0 18.6 Rate stabilization program deferrals 276.0 288.1 Sale and leaseback costs .- (140.9) (150.0)
Loss on reacquired debt 81.6 80.9 Other .. 28.2 33.1 Totaf . . $ 555 9 $ 579 7
- 2. LEASES:
The Company leases certain generating facilities, nuclear fuel, certain transmission facilities, office space and other property and equipment under cancelable and noncancelable leases.
The Company and TE sold their ownership interests in Bruce Mansfield Units 1,2 and 3 and TE sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and TE entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and TE continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and TE have the right, at the end of the respective basic lease terms, to renew the leases. The Company and TE also have the right to purchase the facilities at the expiration of the basic lease term or renewal term (if elected) at a price equal to the fair market value of the facilities.
As co-lessee with TE, the Company is also obligated for TE's lease payments. If TE is unable to make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the Company would be obligated to make such payments. No such payments have been made on behalf of TE. (TE's future minimum lease payments as of
- December 31,1998 were approximately $1.9 billion.)
The Company is buying 150 megawatts of TE's Beaver Valley Unit 2 leased capacity entitlement.
Purchased power expense for this transaction was $98.5 million, $16.8 million, $87.4 million and $99.4 million in 1998, 20
U I the November 8-December 31,1997 penod, the January 1-November 7,1997 period and 1996, respectvely. This l
purchase is awpartad to conenue thiough the end of the lease period. The future nwnimum lease payments through 2017 menacintad with Beaver Vasey Unit 2 are approximately $1.1 bimon.
! ** . Nuclear fuel is cunently financed for the Company and TE through leases with a special-purpose wiW.;un. As of December 31,1998. $156 milbon of nuclear fuel ($88 million for the Company) was financed under a l lease financing arrangement totaling $175 miHion ($60 milhon of intermediate-term notes and $115 minion from bank iC credit arrangements). The notes mature from 1999 through 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 expenses on the Coneoudated Statements of income. Such costs for the three years ended December 31, 1998 are summertred as fogows:
Nov.8- Jan.1 190s Dec. 31.1937 ' Nov. 7.1907 19Bs Qn manene) operaune leases internet element _ . _ _ $ 32.4 510.6 $ 56.0 5 58.1 CMher _ . 74.4 8.4 18.3 4.8 Capitelleeses interest siement . . _ 7.0 1.5 8.5 10.1 Olhar - 38.1 7.5 43.4 51.7 Total rentain . $149.9 19a n $1282 $124 7 The future mirumum lease payments as of December 31,1998 are:
e_-___ -a-Capitel 1.sene Capitel i---- Pavmanta Trust Nat -
Qn mWiene) 1900 835.9 8 89.3 5 62.9 $ 6.4 2000 .. 25.5 86.6 00.5 6.1 2001 16.0 71.7 50.2 21.5 2002 _ 8.2 76.4 70.6 5.8 2003 _ . 3.4 77.5 77.9 (0.4)
Yearn turenhar 10.8' 778_2 584.3 211.9 Totel nunimum lesee paymonte Interest nariton..
90.8 18.1 g,QM, M RlM Presentvalue of not minemum leese paymente _ 83.7 i == cunent nortion.. 30.0 Nancununt nornon . $53.7 The Company and TE refinanced high-cost Axed obugations related to their 1987 sale and leaseback transaction for the Bruce Mansfleid Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 minion aggregate principal amount ($575 minion for the Company and $145 miWon for TE) of first mortgage bonds due in 2000,2004 and 2007 to a trust as security for the issuance of a like principal amount of secured notes due in 2000,2004 and 2007. The obligations of the two companies under there secured notes are joint and severat using available cash, short. term bonowings and the not proceeds from the Offering, the two companies invested $906.5 milNon ($569.4 rnHhon for the Company and $337.1 mulion for TE) Ir, a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem au
$873.2 mimon aggregate principal amount of 10-1/4% and 11 1/8% secured lease obligation bonds (SLOBS) due 2003 and 2016. The SLOBS were issued by a special-purpose-funding corporation in 1988 on behalf of lessors in the two comperwes' 1987 sale and leaseback transecuon. The SNw; igg,it capital trust arrangement effacevely reduces lease L mots related to that transacdon.
\
}
l 21
- 3. CAPITALIZATION:
(A) RETAINED EARNINGS-There are no restnctions on retained eamings for payment of cash dividends on the Company's common -
stock. The merger purchase accounting adjustments included resetting the retained eamings balance to zero at the November 8,1997 merger date. .
(B) COMPREHENSIVEINCOME.
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 dividends to stockholders. Net income and comprehensive income are the same for each period presented.
(C) PREFERRED AND PREFERENCE STOCK-The Company'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 Company in whole, or in part, with 30-90 days' notice.
The preferred dividend rate on the Company's Series L fluctuates based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 1998.
Preference stock authorized for the Company is 3,000,000 shares without par value. No preference shares are currently outstanding.
A liability of $14 million was included in the Company's net assets as of the merger date for preferred dividends declared attributable to the post-merger period. Accordingly, no accrual for preferred stock dividend requirements was included on the Company's November 8,1997 to December 31,1997 Consolidated Statement of income. This liability was subsequently reduced to zero in 1998.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION.
Annual sinking fund provisions for preferred stock are as follows:
Redemption Price Per Series Shares Share Date Beainnina
$ 7.35 C 10,000 $ 100 (i) 88.00 E 3.000 1,000 0) 91.50 Q 10,714 1,000 0) 90.00 S 18,750 1,000 November 1 1999 88,00 R 50.000 1.000 December 1 2001 (i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are $33.5 million in each year 1999 and 2000,
$80.5 million in 2001 $18.0 million in 2002 and $1.0 million in 2003.
(E) LONG-TERM DEBT-The first mortgage indenture and its supplements, which secure all of tne Company's first mortgage .
bonds, serve as direct first mortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Company.
22
Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital l leases)for the next five years are:
1
- h ~' 1
'* 1999 . . . 8144.5 2000 . . . 175.0 2001 . 56.5 C
2032 . 22a.o 200A 115.0 1
The Company's otAgations to repay certain pollution control revenue bonds are securso by several series of first mortgage bonds. One poHution control revenue bond issue is endtled to the benent of an inovocable bank letter of credit of $48,1 mulion. To the extent that drawings are made under this letter of credit to pay principei of, or interest on, the pouution mntrol revenue bonds, the Company is enntled to a credit against its otAgation to repay those bonds. The Comp.ny pays an annual fee of 1.1% of the amount of the letter of credit to the issuing bank and is obligated to
! reimburse the bank for any drawmos thwounder.
l The Company and TE have letters of credit of approximately $225 mHlion in connection with the sale and lamaahar* of Besve/ Valley Unit 2 that expire in June 1999. The letters of credit are secured by Arst mor1 gage bonds of -
the Company and TE in thervr,rk,n of 40% and 60%, respectively (see Note 2).
- 4. 8! tort TERM BORROWING 8:
.. . FirstEnergy has a $100 million revolving credit facility that expires in May 1999. FirstEnergy may bonow under the facility, with all borrowings jointly and severally guaranteed by the Company and TE. FirstEnergy plans to transfer any of its bonowed funds to the Company and TE. The credit agreement is secured with first mortgage bonds of the Company and TE in the pivi,vrn,n of 40% and 60%, respectively The credit agreement also provides the participating banks with a subordinate mortgage security interest in the propertes of the Company and TE. The banks' fee is 0.50% per annum payable quarterly in addibon to interest on any bonowmps. There were no borrowings under the
- facility at December 31,1998. Also, the Company may bonow from its affiliates on a short-term basis. At December 31, 1998, the Company had total short-term bonowings of $80.6 mulion from its affiliates with a weighted average interest rateof approximately5.5%.
- 5. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-l . The Company's current forecast reAects expenditures of approximately $701 mRiion for property additions and improvements from 1999-2003,- of which approximately $150 minion is apf@eNa to 1999. Investments for l- additional nuclear fuel dunng the 1999-2003 penod are ashmated to be approximately $130mimon, of which approximately $14 minion appues to 1999. Dunng the same periods, the Company's nuclear fuel investments are i eW to be reduced by approximately $150 mulion and $32 minion, respectively, as the nuclear fuel is consumed l
NUCLEARINSURANCE.
' The Price-Anderson Act limits the 'public RabRity relative to a single incident at a nuclear power plant to
$9.7 binion. The amount is covered by a combination of private insurance and an industry retrospeceve rating plan.
Based on its present ownership and leasehold interests in Beaver Valley Unit 2, the Davis-Besse Plant and the Pony Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other co owners contribute their proportionate shares of any assessments under the retrospeceve rating plan) would be .
$94.2 miluon per incident but not more than $10.7 minion in any one year for each incident.
. The Company is also insured as to its respeedve interests in Beaver Vaney Unit 2, the Davis-Besse Plant
, .,- and the Pony Plant under poucios issued to the opwating company for each plant. Under these policies, up to-l
- $2.75 bution is provided for pmporty damage and decontamination and C+:+,,,c J=,ing costs.The Company has also obtained .wio4. - i $558 miulon of insurance coverage for replacement power costs for its respective interests in Beaver VaNey Unit 2, Davis-Besse and Pony Under these polices, the Company can be assessed a maximum of
.w.va,- T--$14.1 i muBon for incidents at any covered nuclear faculty occurring during a policy year which are in
. excess of accumulated funds avaHable to the insurer for paying losses The Company intends to mamtain insurance against nuclear risks as described above as long as it is avaRable. To the extent that replacement power, property damage, decontaminabon, decommesioning, repair and 23 i
l
replacement costs and other such costs arising from a nuclear incident at any of the Company's 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 Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remem at risk for such costs. ,
GUARANTEE-The Company, together with the other CAPCO companies, has severaHy guaranteed certain debt and ,
lease obhgatons in connechon with a coal supply contract for the Bruce Mansfield Plant. As of December 31,1998, the Company's share of the guarantee (which approximates fair market value) was $9.4 million. The price under the coal supply contract, which includes certain minimum payments, has been detemwned to be sufRcient to satisfy the debt and
- lease obhgations. The Company's total payments under the coal supply contract were $52.5 million, $51.2 million and
$47.0 million during 1998,1997 and 1996, respectively. The Company's minimum payment for 1999 is approximately j
$14 million. The contract expires December 31,1999.
ENVIRONMENTAL MATTERS-Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The Company has estimated additional capital expenditures for environmental compliance of approximately $145 million, which is included in the construction forecast provided under " Capital Expenditures" for 1999 through 2003.
The Company is in compliance with the current sulfur dioxide (SO3 ) and nitrogen oxides (NO,) reduction requirements under the Clean Air Act Amendments of 1990. SO, reductions in 1999 wiH be achieved by buming lower-suNur fuel, generating more electricity from lower emitting plants, and/or purchasing emission anowances. Plans for l
' WA,g with reduchons required for the year 2000 and theresher have not been finanzed. In September 1998, the !
l Environmental Protection Agency (EPA) finaitzed regulabone requiring additional NO, reductions from the Company's Ohio and Pennsylvania faciuties by May 2003. The EPA's NO, Transport Rule imposes uniform reduchons of NO, enussions across a region of twenty-two states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NO, emissions are contributing significandy to ozone pollution in the eastem United States. By -
September 1999, each of the ta.nt; bo states are required to submit revised State implementation Plans (SIP) which comply with individual state NO, budgets estabhshed by the EPA. These state NO, budgets contemplate an 85% l i
reducuon in uulity plant NO, em ssions from 1990 emissions. A proposed Federal Irnplementation Plan a,cviip&nied the NO, Transport Rule and may be implemented by the EPA in states which fail to revise their SIP. In another separate but related schon, eight states flied pentions with the EPA under Secton 126 of the Clean Air /ct seeking reductions of NO, emissons which are anaged to contribute to ozone poHution in the eight petitioning states. The EPA suggests that the Section 126 petitions will be =":-5t; addressed by the NO, Transport Program, but a September 1998 proposed rulemaidng established an allemative program which would require nearly identical 65% NO, reductions at the Company's Ohio and Pennsylvania plants by May 2003 in the event implementation of the NO, Transport Rule is delayed. FirstEnergy conbnues to evaluate its compuance plans and other comphance options and currently estimates its additional capital expenditures for NO, reductions may reach $500 milhon.
The Company is required to most federaHy approved SO regulations. Volations of such regulations can result in shutdown of the generating unit involved and/or civH or enmmal penalties of up to $25.000 for each day the unit is in violation. The EPA has an interim enforcement poucy for SO regulabons in Ohio that allows for compliance based on a 30 day averaging period. The Company cannot prodlet what action the EPA may take in the future with respect to the interim enforcement policy.
In July 1997, the EPA promulgated changes ir the Nabonal Ambient Air Quality Standard (NAAOS) for ozone and proposud a new NAAQS for previously unregulatou ultra fine particulate matter. The cost of compliance with these regulations may be substantial and depends on the manner in which they are implemented by the states in which
. the Company operates affected faculties The Company has been named as a "potentiaHy responsible party" (PRP) at waste disposal snes which may' require cleanup under the Comprehensive Environmental Response, Ceinpw _ " -i and Liability Act of 1980.
' Anegations that the Company disposed of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subpect to dispute. Federal law provides that au PRPs for a particular site be held liable on a joint and several basis.The Company has accrued a liability of $4.7 minion as of December 31,1998, based on estimates of ,
the costs of cleanup and the proporbonate responsibiuty of other PRPs for such costs. The Company believes that waste disposal costs win not have a malenal adverse effect on its financial condibon, cash flows or results of operations.
l l
24~ j i
i t . I
Q
\
legisidlVe, administrathfe and judicial actions win continue to change the way 9)at the Company must operate in order to comply with environmental laws and reguistions. With respect to any r.ch changes and to the environmental manors described above, the Company expects that while it remains regulated. any resuNing additional capital costs which may be required, as wel as any required increase in operating costs, would ultimately be recovered 7 from its customers.
- 8.
SUMMARY
OF QUARTERLY FINANCIAL DATA (UNAUDITED):
^
The following summarizes certain consohdated operating results by quarter for 1998 and 1997.
tierch 31, June 30, September 30, December 31 Thren aannma - -' inns taas team ions flrr NIEoNel OperetnD Revenues .. - __ $415.0 5465.2 5512.6 5380.5 ria==%n E=aanman and T-- ' 324.3 377.8 3aD.4 321.9 OperetnD mcnme _ 90.7 87.4 123.2 67.6 Operincome 7.6 5.9 8.1 3.7 Not ntaraat Chamma 58.7 An A 81m 't 55.9 Not ..-. . S 30.8 5 34.8 $ 75.0 1 154
.n. _ an m . ..c -= .. a ms s z7.4 z en s s 7.s Thema asenma -e' Iter.31, June 30, Sept. 30, Oct.1 . Nov.8-1987 1987 1987 Nov. 7.1997 h 31.1987 Orr mmeno)
Opersen0 Revenues. $431.6 $428.2 . 5499.5 3 160.7 8254.0 P- ".. 8 = and T 351.8 350.8 388.0 151.3 204.5 C, e., income 80.0 77.4 131.5 18.4 49.5 -
' Otter income (Expones) (3.7) (5.2) 7.5 (1.2) 4.6 Not Interant Chaman 58.1 58_2 71.3 24.0 34.8 income (Loes) Before Extraorthnery_ leem 20.2 14.0 67.7 . (6.8) 19.3 Extraortunary llem (Not of income Taxes) fNota i) .. - - - f324.4) -
Nat nonma ti a==1.. S2:.2 S 14.0 S 87.7 5 331.21 S ' 9.3 E. . 11 amai en G... ==-w. s1 :.s s 4.s z se a Wasa.m a"p.3
- 7. PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME (UNAUDITED):
FirstEnergy was formed on November 8,1997 by the merger of OE and Centenor. The merger was I accounted for as a purchase of Centerior's not ascots with 77,637,704 shares of F;rMCisigy Common Stock through !
the conversion of each outstanding Centerior Common Stock share into 0.525 of a share of FirstEnergy Common !
Stock (fractional shares were paid in cash). Based on an imputed value of $20.125 por share, the purchase price I was approximately $1.582 bluion, which also included approximately $20 minion of merger related costs. Goodwill of I approximately $2.0 billion was recognized (to be amortized on a straight-line basis over forty years), which i.,,i-- ^ ,W the excess of the purchase price over Centerior's not assets after fair value adjustments. l l
Accumulated amortization of goodwill was appmmimately $44 minion as of December 31,1998. The i merger purchase accountmg adjustments included recognizing estimated severance and other compensation ,
liabihties ($56 miHion). The amount charged against the liability in 1998 relating to the costs of involuntary employee :
separation was $30 million. The liability was subsequently reduced to approximately $9 million as of December 31, 1998 to repsweent potential costs associated with the separation of 493 Company employees. The liability -
adjustment was offset by a corresponding reduction to goodwill recognized in connection with the Centerior acquisition.
,, . : The fonowing pro forma statements of income for the Company give effect to the OE-Centarior merger as if it had been consummated on January 1,1998, with the purchase accounting adjustments actually recognized in the business combination.
l 25
s Year Ended December 31.
1997 190s (hr anNNons) operaung Revenues . . . . . . . . . ,
$1.783 $1.790
, operamng Expenses and Taxes. .. ._. , ..... ...... . J.,UA _1A21 operaeng income ... .. ... . . .. . ... .. 365 aos ,
osherincome . 15 2- .
Not interest Chergos . . . . . . . . 232' ._22Z Not lncoma .. I 148 $ 141 Pro forms adjustments reflected above include: (1) adjusting the Company's nuclear generstmg units to fair value based upon independent appraisals and estimated discounted future cash flows based on management's estimate of cost recovery; (2) the effect of discontinuing SFAS 71 for the Company's nuclear operations; (3) amortization of the fair value adjustment for long-term debt; (4) goodwul recognized representing the excess of the Company's portion of the purchase price over the Company's adjusted not assets; (5) the elimination of merger costs; and (6) adjustments for estimated tax effects of the above adjustments.
- 8. PENDING MERGER OF TE INTO THE C00APANY:
In March 1994, Centerior announced a plan to merge TE into the Company. All necessary regulatory approvals have been obtained, except the approval of the Nuclear Regulatory Commission (NRC). This application
' was withdrawn at the NRC's request pending the decision whether to complete this merger. No final decision regarding the proposed merger has been reached in June'1995 TE's preferred stockholders approved the merger and the Company's preferred stockholders approved the authorization of additional shares of preferred stock. If and when the merger becomes effective, TE's preferred stockholders will exchange their shares for preferred stock shares of the Company having substantially the same terms. Debt holders of the merging compamos will become debt holders of the Company.
For the merging companies, the combined pro forma operating revenues were $2.621 billion,
$2.527 bulion and $2.554 billion and the combined pro forma not income was $272 million, $220 minion (oxcluding the extraordinary item discussed in Note 1 and a similar item for TE) and $218 million for the years 1998,1997 and 1996, respectively. The pro forma data is based on accounting for the merger of the Company and TE on a method similar to a pooling of interests and for 1997 and 1996 includes pro forma adjustments to reflect the effect of the OE-Centerior merger. The pro forma data is not necessarHy indicative of the results of operations which would have been reported had the merger been in effect during those years or which may be reported in the future. The pro forma data should be read in conjunction with the audited financial statements of both the Company and TE.
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i Report of Independent Pub!!c Accountants To the Stockholders and Board of Directors of The Cleveland Electric illuminating Company:
, We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The l Cleveland Electric filuminating Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and j subsidiary as of December 31,1998 and 1997, and the related consolidated statements of income, common j stockholder's equity, preferred stock, cash flows and taxes for the year ended December 31,1996, the period from j
. January 1,1997 to November 7,1997 (pre-merger), the period from November 8,1997 to December 31,1997 (post- l merger), and the year ended December 31,1998. These financial statements are the responsibility of the Cormany's l management. Our responsibility is to express an opinion on these financial statements based on our audits. 1 We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we I plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of inaterial j misstatement"An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the i financial statements. An audit also includes assessing the accounting principles used and significant estimates mada 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 fairiy, in all material respects, the financial position of l The Cleveland Electric illuminating Company and subsidiary as of December 31,1998 and 1997, and the results of their operations and their cash flows for the year ended December 31,1996, the period from January 1,1997 to November 7, 1997 (pre-merger the period from November 8,1997 to December 31,1997 (post-merger), and the year ended December 31,1993, in conformity with generally accepted accounting principles. !
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ARTHUR ANDERSEN LLP Cleveland, Ohio February 12,1999 j l
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c/o FirstEnergy Corp.
76 South Main Street Akron, Ohio 44308 (800)736-3402 1998 Annual Report 4
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