THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
2000 ANNUAL REPORT TO STOCKHOLDERS
The Cleveland Electric Illuminating Company is a wholly owned
electric utility operating subsidiary of FirstEnergy Corp. It engages in
the generation, distribution and sale of electric energy in an area of
approximately 1,700 square miles in northeastern Ohio. It also engages in
the sale, purchase and interchange of electric energy with other electric
companies. The area it serves has a population of approximately 1.9
million.
Contents Page
- -------- ----
Selected Financial Data 1
Management's Discussion and Analysis 2-6
Consolidated Statements of Income 7
Consolidated Balance Sheets 8
Consolidated Statements of Capitalization 9-10
Consolidated Statements of Common Stockholder's Equity 11
Consolidated Statements of Preferred Stock 11
Consolidated Statements of Cash Flows 12
Consolidated Statements of Taxes 13
Notes to Consolidated Financial Statements 14-23
Report of Independent Public Accountants 24
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
SELECTED FINANCIAL DATA
Nov. 8- Jan. 1-
2000 1999 1998 Dec. 31, 1997 Nov. 7, 1997 1996
- ------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands) |
|
|
GENERAL FINANCIAL INFORMATION: |
|
Operating Revenues $1,887,039 $1,864,954 $1,795,997 $ 254,892 | $1,537,459 $1,798,850
========== ========== ========== ========== | ========== ==========
|
Operating Income $ 390,094 $ 394,766 $ 382,523 $ 50,431 | $ 315,777 $ 367,509
========== ========== ========== ========== | ========== ==========
|
Income Before Extraordinary Item $ 202,950 $ 194,089 $ 164,891 $ 19,290 | $ 95,191 $ 116,553
========== ========== ========== ========== | ========== ==========
|
Net Income (Loss) $ 202,950 $ 194,089 $ 164,891 $ 19,290 | $ (229,247) $ 116,553
========== ========== ========== ========== | ========== ==========
|
Earnings (Loss) on Common Stock $ 182,107 $ 160,565 $ 140,097 $ 19,290 | $ (274,276) $ 77,810
========== ========== ========== ========== | ========== ==========
|
Total Assets $5,964,631 $6,208,761 $6,318,183 $6,440,284 | $6,962,297
========== ========== ========== ========== | ==========
|
CAPITALIZATION: |
Common Stockholder's Equity $1,064,839 $ 966,616 $1,008,238 $ 950,904 | $1,044,283
Preferred Stock- |
Not Subject to Mandatory Redemption 238,325 238,325 238,325 238,325 | 238,325
Subject to Mandatory Redemption 26,105 116,246 149,710 183,174 | 186,118
Long-Term Debt 2,634,692 2,682,795 2,888,202 3,189,590 | 2,523,030
---------- ---------- ---------- ---------- | ----------
Total Capitalization $3,963,961 $4,003,982 $4,284,475 $4,561,993 | $3,991,756
========== ========== ========== ========== | ==========
|
CAPITALIZATION RATIOS: |
Common Stockholder's Equity 26.9% 24.1% 23.5% 20.9% | 26.2%
Preferred Stock- |
Not Subject to Mandatory Redemption 6.0 6.0 5.6 5.2 | 6.0
Subject to Mandatory Redemption 0.6 2.9 3.5 4.0 | 4.6
Long-Term Debt 66.5 67.0 67.4 69.9 | 63.2
----- ----- ----- ----- | -----
Total Capitalization 100.0% 100.0% 100.0% 100.0% | 100.0%
===== ===== ===== ===== | =====
|
KILOWATT-HOUR SALES (Millions): |
Residential 5,061 5,278 4,949 790 | 4,062 4,958
Commercial 6,656 6,509 6,353 893 | 4,990 5,908
Industrial 8,320 8,069 8,024 1,285 | 6,710 7,977
Other 167 166 165 89 | 476 522
------ ------ ------ ----- | ------ ------
Total Retail 20,204 20,022 19,491 3,057 | 16,238 19,365
Total Wholesale 4,632 2,607 1,275 575 | 2,408 2,155
------ ------ ------ ----- | ------ ------
Total 24,836 22,629 20,766 3,632 | 18,646 21,520
====== ====== ====== ===== | ====== ======
|
CUSTOMERS SERVED: |
Residential 667,115 667,954 668,470 671,265 | 663,130
Commercial 69,103 69,954 68,896 74,751 | 70,886
Industrial 4,851 5,090 5,336 6,515 | 6,545
Other 307 223 221 278 | 446
------- ------- ------- ------- | -------
Total 741,376 743,221 742,923 752,809 | 741,007
======= ======= ======= ======= | =======
|
Number of Employees (a) 1,046 1,694 1,798 3,162 | 3,282
<FN>
(a) Reduction in 2000 reflects transfer of responsibility for generation
operations to FirstEnergy Corp.'s competitive services unit.
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 is subject to certain
risks and uncertainties. Such statements typically contain, but are not
limited to, the terms anticipate, potential, expect, believe, estimate and
similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and
margins, changes in markets for energy services, changing energy and
commodity market prices, legislative and regulatory changes (including
revised environmental requirements), and the availability and cost of
capital.
Results of Operations
- ---------------------
Earnings on common stock increased 13% to $182.1 million in 2000
from $160.6 million in 1999. Results in 2000 were favorably affected by
higher operating revenues and reduced depreciation and amortization, net
interest charges and preferred stock dividend requirements. In 1999,
earnings on common stock increased 15% to $160.6 million from $140 million
in 1998 primarily due to higher operating revenues, the absence of
unusually high purchased power costs experienced in 1998, reduced general
taxes and lower net interest charges. Partially offsetting the improved
earnings in both 2000 and 1999 were higher nuclear and other operating
costs.
Operating revenues increased by $22.1 million in 2000 following
a $69.0 million increase in 1999. The sources of increases in operating
revenues during 2000 and 1999, as compared to the prior year, are
summarized in the following table.
Sources of Revenue Changes 2000 1999
- -----------------------------------------------------------
Increase (Decrease) (In millions)
Increase in retail kilowatt-hour
sales $ 15.6 $46.1
Change in average retail price (37.9) (1.5)
Increase in wholesale sales 56.1 15.2
All other changes (11.7) 9.2
- -----------------------------------------------------------
Net Increase in Operating Revenues $ 22.1 $69.0
==========================================================
Electric Sales
Additional kilowatt-hour sales to the wholesale market were the
largest source of the increase in operating revenues in 2000, compared to
the prior year, due in part to additional available generating capacity.
Operating revenues from increased kilowatt-hour sales to retail customers
were more than offset by a reduction in average retail unit prices in
2000, compared to 1999. While sales to commercial and industrial customers
both increased in 2000, sales to residential customers decreased in part
due to the cooler summer weather, as compared to the above normal
temperatures experienced during 1999. Other electric revenues were also
lower in 2000 as a result of the elimination of steam sales and the
absence of joint ownership billings to Duquesne Light Company (Duquesne)
in 2000 resulting from the asset swap with Duquesne in early December
1999. The decline in other revenues was partially offset by additional
transmission-related revenues in 2000, compared to the prior year.
Operating revenues in 1999 increased from the preceding year as
a result of kilowatt-hour sales growth in both the retail and wholesale
markets. Strong consumer-driven economic growth, and to a lesser extent
the weather, contributed to the increased retail sales. Weather-induced
electricity demand in the wholesale market and additional available
internal generation combined to more than double sales to wholesale
customers in 1999, compared to 1998. Changes in kilowatt-hour sales by
customer class in 2000 and 1999 are summarized in the following table:
Changes in KWH Sales 2000 1999
- ------------------------------------------------
Increase (Decrease)
Residential (4.1)% 6.6%
Commercial 2.3% 2.5%
Industrial 3.1% 0.6%
- ------------------------------------------------
Total Retail 0.9% 2.7%
Wholesale 77.6% 104.5%
- ------------------------------------------------
Total Sales 9.8% 9.0%
- ------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes increased $26.8 million in
2000 and $56.7 million in 1999, compared to the respective preceding year.
Collectively, nuclear and other operating costs represented a majority of
the increased costs in 2000 and all of the increase in 1999. General taxes
were also higher in 2000.
Fuel and purchased power costs increased a moderate $4.8 million
in 2000, compared to 1999. The slightly higher costs resulted from a $44.8
million increase in purchased power costs which was significantly offset
by a $40.0 million decrease in fuel expense. Most of the increase in
purchased power costs occurred in the second quarter as generating unit
refueling and maintenance outages reduced internal generation during that
period. The reduction in fuel expense in 2000 from the preceding year
occurred despite a 3.4% increase in internal generation. Factors
contributing to the lower fuel expense included:
o A higher proportion of nuclear generation (which has lower unit fuel
costs than fossil fuel) due to increased nuclear ownership from the
exchange of generating assets with Duquesne in December 1999;
o The expiration of an above-market coal contract at the end of 1999;
and
o Continued improvement of coal-blending strategies, which resulted in
the use of additional lower-cost coal and enhanced the efficiency
and cost-competitiveness of our fossil generation.
In 1999, lower purchased power costs accounted for almost all of
the $26.5 million reduction in fuel and purchased power costs from the
prior year. Much of the decrease in purchased power costs occurred in the
second quarter of 1999 due to the absence of unusual conditions
experienced in the summer of 1998. The higher purchased power costs were
incurred during a period of record heat and humidity in late June 1998,
which coincided with a regional power shortage resulting in high prices
for purchased power. Unscheduled outages at Beaver Valley Unit 2, the
Davis-Besse Plant and Avon Lake Unit 9 required us to purchase significant
amounts of power on the spot market during that period. Although above
normal temperatures were also experienced in 1999, we maintained a
stronger capacity position compared to the previous year and better met
customer demand from our own internal generation.
Nuclear operating costs increased $12.9 million in 2000,
compared to 1999, primarily due to additional refueling outage costs
associated with three unit outages in 2000 versus two during the previous
year and increased ownership of the Perry Plant resulting from the
Duquesne asset swap. Nuclear refueling outage costs at Beaver Valley Unit
2 and the Perry Plant were primarily responsible for the $40.8 million
increase in 1999 nuclear operating costs from the preceding year. Other
operating costs rose $6.7 million in 2000, compared to 1999, with most of
the increase resulting from additional leased portable diesel generators,
acquired as part of our summer supply strategy, and voluntary early
retirement costs. Partially offsetting these higher costs were increased
gains of $7.8 million realized from the sale of emission allowances in
2000. Other operating costs increased $32.5 million in 1999 from 1998 due
to higher customer and sales expenses including expenditures for energy
marketing programs, information system requirements and other customer-
related costs.
Approval of our transition plan by the Public Utilities
Commission of Ohio (PUCO) resulted in a net reduction of depreciation and
amortization in 2000, compared to 1999. As part of the transition plan,
generating plant assets were reviewed for possible impairment. Impaired
nuclear plant investments were recognized as regulatory assets, for which
recovery as transition costs began in January 2001. This reduction in
plant investment resulted in a corresponding reduction to depreciation
expense beginning in July 2000 and accounted for most of the $10.3 million
reduction in depreciation and amortization in 2000 from the preceding
year. Higher general taxes in 2000, compared to the prior year, resulted
from favorable Ohio and Pennsylvania property tax settlements in 1999.
Net Interest Charges
Net interest charges decreased by $10.1 million in 2000 and
$19.6 million in 1999, compared to the prior year. We continue to redeem
our outstanding debt, thus maintaining the downward trend in our financing
costs during 2000. Net redemptions of long-term debt totaled $175 million
in 2000.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements were $12.7 million lower
in 2000, compared to the prior year, as a result of preferred stock
maturities and the amortization of fair market value adjustments
recognized under purchase accounting in 1997. In 1999, preferred stock
dividend requirements were $8.7 million higher due to a reduction in 1998
resulting from the declaration of $9 million of preferred dividends as of
the 1997 merger date, for dividends attributable to 1998.
Effects of SFAS 71 Discontinuation and Impairment
- -------------------------------------------------
The application of the Statement of Financial Accounting
Standards No. (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," was discontinued for our nonnuclear generation business
effective with approval by the PUCO of the Ohio transition plan. We
continue to bill and collect cost-based rates for transmission and
distribution services, which remain subject to cost-based regulation;
accordingly, it is appropriate that we continue the application of SFAS 71
to those operations. All generating plant investments were reviewed for
impairment due to anticipated changes to our cash flows resulting from the
transition plan. The June 30, 2000 balance sheet reflects the effect of
that review with nuclear plant investment being further reduced by a total
of $304 million with a corresponding recognition of regulatory assets for
the impaired plant, which is recoverable through future regulatory cash
flows.
Financial Condition, Capital Resources and Liquidity
- ----------------------------------------------------
On September 1, 2000, FirstEnergy Corp.'s electric utility
operating companies transferred $1.2 billion of their transmission assets
to American Transmission Systems, Inc. (ATSI), an affiliated company. ATSI
represents a first step toward the goal of establishing a larger
independent, regional transmission organization. As part of the transfer,
we sold to ATSI $328.1 million of our transmission assets, net of $155.2
million of accumulated depreciation and $3.4 million of investment tax
credits for $76.3 million in cash and $93.2 million in long-term notes.
Through net debt redemptions and preferred stock sinking fund
maturities, we continued to reduce the cost of debt and preferred stock,
and improve our financial position in 2000. During 2000, we reduced our
total debt by approximately $245 million. Our common stockholder's equity
percentage of capitalization increased to 27% as of December 31, 2000 from
21% at the end of 1997. We have reduced the average capital cost of
outstanding debt from 8.88% in 1995 to 8.07% in 2000. Net redemptions of
long-term debt and preferred stock completed in 2000 are expected to
generate annual savings of about $15 million. Also, approval by the PUCO
of our transition plan on July 19, 2000 (see Outlook), was cited as an
important reason that Moody's Investors Service and Fitch upgraded our
debt ratings during the second half of 2000. The improved credit ratings
should lower the cost of future borrowings. Our credit ratings remain
under review for further possible upgrades by Moody's. The improved credit
ratings are summarized in the following table:
Credit Ratings Before Upgrade After Upgrade
- -------------------------------------------------------------
Moody's Moody's
Investors Investors
Service Fitch Service Fitch
- -------------------------------------------------------------
First mortgage bonds Ba1 BB+ Baa3 BBB-
Preferred Stock b1 B baa1 BB
Our cash requirements in 2001 for operating expenses,
construction expenditures and scheduled debt maturities are expected to be
met without issuing additional securities. We have cash requirements of
approximately $1.1 billion for the 2001-2005 period to meet scheduled
maturities of long-term debt and preferred stock. Of that amount,
approximately $137.0 million relates to 2001.
We had about $3.2 million of cash and temporary investments and
$28.6 million of short-term indebtedness to associated companies on
December 31, 2000. Under our first mortgage indenture, as of December 31,
2000, we would have been permitted to issue up to $829 million of
additional first mortgage bonds on the basis of property additions and
retired bonds. We have no restrictions on the issuance of preferred stock.
Our capital spending for the period 2001-2005 is expected to be
about $455 million (excluding nuclear fuel), of which approximately $103
million applies to 2001. Investments for additional nuclear fuel during
the 2001-2005 period are estimated to be approximately $114 million, of
which about $8 million relates to 2001. During the same periods, our
nuclear fuel investments are expected to be reduced by approximately $144
million and $32 million, respectively, as the nuclear fuel is consumed.
Also, we have operating lease commitments net of trust cash receipts of
approximately $74 million for the 2001-2005 period, of which approximately
$22 million relates to 2001.
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced
since a significant portion of our debt has fixed interest rates, as noted
in the table below. We are subject to the inherent interest rate risks
related to refinancing maturing debt by issuing new debt securities. As
discussed in Note 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 corresponding changes 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.
Comparison of Carrying Value to Fair Value
- ------------------------------------------------------------------------------------------------
There- Fair
2001 2002 2003 2004 2005 after Total Value
- ------------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than
Cash and Cash Equivalents:
Fixed Income $16 $ 38 $ 48 $ 1 $ 21 $ 525 $ 649 $ 656
Average interest rate 7.8% 7.7% 7.6% 7.8% 7.9% 7.3% 7.4%
- -------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $57 $228 $115 $280 $300 $1,395 $2,375 $2,467
Average interest rate 8.6% 7.7% 7.4% 7.7% 9.5% 7.4% 7.7%
Variable rate $ 188 $ 188 $ 188
Average interest rate 4.6% 4.6%
Short-term Borrowings $29 $ 29 $ 29
Average interest rate 6.4% 6.4%
- -------------------------------------------------------------------------------------------------
Preferred Stock $80 $ 19 $ 1 $ 1 $ 1 $ 3 $ 105 $ 105
Average dividend rate 8.9% 8.9% 7.4% 7.4% 7.4% 7.4% 8.8%
- -------------------------------------------------------------------------------------------------
Outlook
- -------
On July 19, 2000, the PUCO approved FirstEnergy's plan for
transition to customer choice in Ohio (see Note 1), filed on our behalf,
as well as for our affiliated Ohio electric utility operating companies -
OE and TE. As part of its authorization, the PUCO approved a settlement
agreement between FirstEnergy and major groups representing most of
FirstEnergy's Ohio customers regarding the transition to customer choice
in selection of electricity suppliers. On January 1, 2001, electric choice
became available to FirstEnergy's Ohio customers. Under the plan, we
continue to deliver power to homes and businesses through our existing
distribution system, which remains regulated. However, our rates have been
restructured to establish separate charges for transmission and
distribution, transition cost recovery and a generation-related component.
When one of our Ohio customers elects to obtain power from an alternative
supplier, we reduce the customer's bill with a "generation shopping
credit," based on market prices plus an incentive, and the customer
receives a generation charge from the alternative supplier.
The transition cost portion of rates provides for recovery of
certain amounts not otherwise recoverable in a competitive generation
market (such as regulatory assets). The transition costs will be paid by
all customers regardless of whether or not they choose an alternative
supplier. Under the plan, we assume the risk of not recovering up to $170
million of transition revenue if the rate of customers (excluding
contracts and full-service accounts), switching their service from us has
not reached an average of 20% over any consecutive twelve-month period by
December 31, 2005 - the end of the market development period. We also
committed under the transition agreement to make available 400 MW of our
generating capacity to marketers, brokers and aggregators at set prices,
to be used for sales only to retail customers in our Ohio service areas.
Through February 8, 2001, approximately 305 MW of the 400 MW supply
commitment had been secured by alternative suppliers. We began accepting
customer applications for switching to alternative suppliers on December
8, 2000; as of February 8, 2001, we had been notified that about 51,000 of
our customers requested generation services from other authorized
suppliers, including FirstEnergy Services Corp. (FE Services), an
affiliated company.
Beginning in 2001, Ohio utilities that offer both competitive
and regulated retail electric services must implement a corporate
separation plan approved by the PUCO -- one which provides a clear
separation between regulated and competitive operations. Since
FirstEnergy's regionally-focused retail sales strategy envisions the
continued operation of both regulated and competitive operations, its
transition plan included details for its corporate separation. The
approved plan is consistent with the way FirstEnergy managed its
businesses in 2000, through a competitive services unit, a utility
services unit and a corporate support services unit. FE Services provides
competitive retail energy services while we continue to provide regulated
transmission and distribution services. FirstEnergy Generation Corp. (FE
Generation), an associated company, operates and leases fossil plants from
us. We expect that the transfer of our fossil generating assets to FE
Generation will be completed by the end of the market development period.
All of our power supply requirements are provided by FE Services to
satisfy our "provider of last resort" obligation under the FirstEnergy
transition plan, as well as grandfathered wholesale contracts.
We are in compliance with current sulfur dioxide and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of
1990. In 1998, the EPA finalized regulations requiring additional NOx
reductions in the future from our Ohio and Pennsylvania facilities (see
Note 5). We continue to evaluate our compliance plans and other compliance
options.
In July 1997, the EPA changed the National Ambient Air Quality
Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the
U.S. Court of Appeals found constitutional and other defects in the new
NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS
rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules.
The future cost of compliance with these regulations may be substantial
and will depend on the manner in which they are ultimately implemented, if
at all, by the states in which we operate affected facilities.
Under federal environmental law and related federal and state
waste regulations, certain fossil-fuel combustion waste products, such as
coal ash, were exempted from hazardous waste disposal requirements pending
the EPA's evaluation of the need for future regulation. The EPA has issued
its final regulatory determination that regulation of coal ash as a
hazardous waste is unnecessary. On April 25, 2000, the EPA announced that
it will develop national standards regulating disposal of coal ash as a
nonhazardous waste.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from
electric power plants. The EPA identified mercury as the hazardous air
pollutant of greatest concern. The EPA established a schedule to propose
regulations by December 2003 and issue final regulations by December 2004.
The future cost of compliance with these regulations may be substantial.
We have been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and
the liability involved, are often unsubstantiated and subject to dispute.
Federal law provides that all PRPs for a particular site be held liable on
a joint and several basis. We have an accrued liability totaling $3.4
million as of December 31, 2000, based on estimates of the total costs of
cleanup, the proportionate responsibility of other PRPs for such costs,
and the financial ability of other PRPs to pay. We believe that waste
disposal costs will not have a material adverse effect on our financial
condition, cash flow or results of operation.
On August 8, 2000, our parent company, FirstEnergy Corp.,
entered into an agreement to merge with GPU, Inc, a Pennsylvania
corporation, headquartered in Morristown, New Jersey. The target date for
completing the merger is by the end of the second quarter of 2001. We will
continue to be a wholly owned subsidiary of FirstEnergy Corp.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES $1,887,039 $1,864,954 $1,795,997
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power 414,127 409,282 435,752
Nuclear operating costs 151,571 138,686 97,914
Other operating costs 374,818 368,103 335,621
---------- ---------- ----------
Total operation and maintenance expenses 940,516 916,071 869,287
Provision for depreciation and amortization 220,915 231,225 234,348
General taxes 222,297 211,636 221,077
Income taxes 113,217 111,256 88,762
---------- ---------- ----------
Total operating expenses and taxes 1,496,945 1,470,188 1,413,474
---------- ---------- ----------
OPERATING INCOME 390,094 394,766 382,523
OTHER INCOME 12,568 9,141 11,772
---------- ---------- ---------
INCOME BEFORE NET INTEREST CHARGES 402,662 403,907 394,295
---------- ---------- ---------
NET INTEREST CHARGES:
Interest on long-term debt 199,444 211,842 234,795
Allowance for borrowed funds used during
construction (2,027) (1,755) (2,079)
Other interest expense (credit) 2,295 (269) (3,312)
---------- ---------- ----------
Net interest charges 199,712 209,818 229,404
---------- ---------- ----------
NET INCOME 202,950 194,089 164,891
PREFERRED STOCK DIVIDEND
REQUIREMENTS 20,843 33,524 24,794
---------- ---------- ----------
EARNINGS ON COMMON STOCK $ 182,107 $ 160,565 $ 140,097
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999
- -------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $4,036,590 $4,479,098
Less-Accumulated provision for depreciation 1,624,672 1,498,798
---------- ----------
2,411,918 2,980,300
---------- ----------
Construction work in progress-
Electric plant 66,904 55,002
Nuclear fuel 24,145 408
---------- ----------
91,049 55,410
---------- ----------
2,502,967 3,035,710
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2) 491,830 517,256
Nuclear plant decommissioning trusts 189,804 183,291
Long-term notes receivable from associated companies 92,722 --
Other 36,084 20,708
---------- ----------
810,440 721,255
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 2,855 376
Receivables-
Customers 14,748 17,010
Associated companies 81,090 18,318
Other (less accumulated provisions of $1,000,000
for uncollectible accounts at both dates) 127,639 171,274
Notes receivable from associated companies 384 --
Materials and supplies, at average cost-
Owned 26,039 39,294
Under consignment 38,673 23,721
Prepayments and other 59,377 56,447
---------- ----------
350,805 326,440
---------- ----------
DEFERRED CHARGES:
Regulatory assets 816,143 539,824
Goodwill 1,408,869 1,440,283
Property taxes 64,230 132,643
Other 11,177 12,606
---------- ----------
2,300,419 2,125,356
---------- ----------
$5,964,631 $6,208,761
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of
Capitalization):
Common stockholder's equity $1,064,839 $ 966,616
Preferred stock-
Not subject to mandatory redemption 238,325 238,325
Subject to mandatory redemption 26,105 116,246
Long-term debt 2,634,692 2,682,795
---------- ----------
3,963,961 4,003,982
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock 165,696 240,684
Accounts payable-
Associated companies 102,915 85,950
Other 54,422 50,570
Notes payable to associated companies 28,586 103,471
Accrued taxes 178,707 177,006
Accrued interest 56,142 60,740
Other 82,195 83,292
---------- ----------
668,663 801,713
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 591,748 567,478
Accumulated deferred investment tax credits 79,957 86,999
Nuclear plant decommissioning costs 198,997 192,484
Pensions and other postretirement benefits 227,528 220,731
Other 233,777 335,374
---------- ----------
1,332,007 1,403,066
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5) ---------- ----------
$5,964,631 $6,208,761
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these balance sheets.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2000 1999
- ------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 105,000,000 shares
79,590,689 shares outstanding $ 931,962 $ 931,962
Retained earnings (Note 3A) 132,877 34,654
---------- ----------
Total common stockholder's equity 1,064,839 966,616
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
-------------------- --------------------
2000 1999 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3B):
Cumulative, without par value-
Authorized 4,000,000 shares
Not Subject to Mandatory Redemption:
$ 7.40 Series A 500,000 500,000 $ 101.00 $ 50,500 50,000 50,000
$ 7.56 Series B 450,000 450,000 102.26 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 200,000 200,000 500.00 100,000 96,850 96,850
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption 1,624,000 1,624,000 $243,917 238,325 238,325
========= ========= ======== ---------- ----------
Subject to Mandatory Redemption
(Note 3C):
$ 7.35 Series C 80,000 90,000 101.00 $ 8,080 8,041 9,110
$88.00 Series E -- 3,000 -- -- -- 3,000
$91.50 Series Q 10,716 21,430 1,000.00 10,716 10,716 21,430
$88.00 Series R 50,000 50,000 -- -- 51,128 55,000
$90.00 Series S 36,500 55,250 -- -- 36,686 61,170
Redemption Within One Year (80,466) (33,464)
--------- ---------- -------- ---------- ----------
Total Subject to Mandatory
Redemption 177,216 219,680 $ 18,796 26,105 116,246
========= ========== ======== ---------- ----------
LONG-TERM DEBT (Note 3D):
First mortgage bonds:
7.625% due 2002 195,000 195,000
7.375% due 2003 100,000 100,000
9.500% due 2005 300,000 300,000
6.860% due 2008 125,000 125,000
9.000% due 2023 150,000 150,000
----------- ----------
Total first mortgage bonds 870,000 870,000
----------- ----------
Unsecured notes:
* 5.580% due 2033 27,700 27,700
----------- ----------
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
7.000% due 2001-2009 1,820 1,850
7.190% due 2000 -- 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
8.000% due 2013 78,700 78,700
* 4.206% due 2015 39,835 39,835
7.880% due 2017 300,000 300,000
* 4.171% due 2018 72,795 72,795
* 4.950% due 2020 47,500 47,500
6.000% due 2020 62,560 62,560
6.100% due 2020 70,500 70,500
9.520% due 2021 7,500 7,500
6.850% due 2023 30,000 30,000
8.000% due 2023 46,100 46,100
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 5,993
5.350% due 2030 23,255 23,255
4.600% due 2030 81,640 81,640
---------- ----------
Total secured notes 1,665,548 1,840,578
---------- ----------
Capital lease obligations (Note 2) 93,422 79,204
---------- ----------
Net unamortized premium on debt 63,252 72,533
---------- ----------
Long-term debt due within one year (85,230) (207,220)
---------- ----------
Total long-term debt 2,634,692 2,682,795
---------- ----------
TOTAL CAPITALIZATION $3,963,961 $4,003,982
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2000 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Comprehensive Number Carrying Retained
Income of Shares Value Earnings
------------- --------- ---------- ---------
(Dollars in thousands)
Balance, January 1, 1998 79,590,689 $931,614 $ 19,290
Purchase accounting fair value
adjustment 348
Net income $164,891 164,891
========
Cash dividends on preferred stock (21,947)
Cash dividends on common stock (85,958)
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1998 79,590,689 931,962 76,276
Net income $194,089 194,089
========
Cash dividends on preferred stock (36,737)
Cash dividends on common stock (198,974)
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1999 79,590,689 931,962 34,654
Net income $202,950 202,950
========
Cash dividends on preferred stock (20,727)
Cash dividends on common stock (84,000)
- -------------------------------------------------------------------------------------------------
Balance, December 31, 2000 79,590,689 $931,962 $ 132,877
==================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Number Carrying Number Carrying
of Shares Value of Shares Value
--------- ----- --------- -----
(Dollars in thousands)
Balance, January 1, 1998 1,624,000 $238,325 285,858 $197,888
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
- -------------------------------------------------------------------------------------------
Balance, December 31, 1998 1,624,000 238,325 262,144 183,174
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$90.00 Series S (18,750) (18,750)
- -------------------------------------------------------------------------------------------
Balance, December 31, 1999 1,624,000 238,325 219,680 149,710
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$90.00 Series S (18,750) (18,750)
Amortization of fair market
value adjustments-
$ 7.35 Series C (69)
$88.00 Series R (3,872)
$90.00 Series S (5,734)
- -------------------------------------------------------------------------------------------
Balance, December 31, 2000 1,624,000 $238,325 177,216 $106,571
===========================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 202,950 $ 194,089 $ 164,891
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 220,915 231,225 234,348
Nuclear fuel and lease amortization 37,217 33,912 35,361
Other amortization (11,635) (10,730) (12,677)
Deferred income taxes, net 22,373 33,060 13,031
Investment tax credits, net (3,617) (3,947) (5,185)
Receivables (16,875) (31,544) (38,527)
Materials and supplies (1,697) 18,818 (8,933)
Accounts payable 20,817 26,525 (10,481)
Other (44,188) (11,283) (22,772)
--------- --------- ---------
Net cash provided from operating activities 426,260 480,125 349,056
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt -- 26,355 232,919
Ohio Schools Council prepayment program -- -- 116,598
Short-term borrowings, net -- 22,853 23,816
Redemptions and Repayments-
Preferred stock 33,464 33,464 14,714
Long-term debt 212,771 214,405 488,610
Short-term borrowings, net 74,885 -- --
Dividend Payments-
Common stock 84,000 198,974 85,958
Preferred stock 30,518 33,524 34,841
--------- --------- ---------
Net cash used for financing activities 435,638 431,159 250,790
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 96,236 122,194 72,130
Loans to associated companies 93,106 -- 53,509
Loan payments from associated companies -- (53,509) --
Capital trust investments (25,426) (25,905) (31,923)
Sale of assets to associated companies (197,902) -- --
Other 22,129 25,336 18,799
--------- --------- ---------
Net cash used for (provided from) investing activities (11,857) 68,116 112,515
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 2,479 (19,150) (14,249)
Cash and cash equivalents at beginning of year 376 19,526 33,775
--------- --------- ---------
Cash and cash equivalents at end of year $ 2,855 $ 376 $ 19,526
========= ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $ 208,085 $ 221,360 $ 238,950
========= ========= =========
Income taxes $ 109,212 $ 92,555 $ 100,107
========= ========= =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 131,331 $ 120,725 $ 130,642
State gross receipts 79,709 78,197 78,344
Social security and unemployment 11,464 10,941 9,029
Other (207) 1,773 3,062
--------- --------- ---------
Total general taxes $ 222,297 $ 211,636 $ 221,077
========= ========= =========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 106,986 $ 92,627 $ 90,690
State 959 2,129 2,158
--------- --------- ---------
107,945 94,756 92,848
--------- --------- ---------
Deferred, net-
Federal 23,265 33,369 12,981
State (892) (309) 50
--------- --------- ---------
22,373 33,060 13,031
--------- --------- ---------
Investment tax credit amortization (3,617) (3,947) (5,185)
--------- --------- ---------
Total provision for income taxes $ 126,701 $ 123,869 $ 100,694
========= ========= =========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income $ 113,217 $ 111,256 $ 88,762
Other income 13,484 12,613 11,932
--------- --------- ---------
Total provision for income taxes $ 126,701 $ 123,869 $ 100,694
========= ========= =========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 329,651 $ 317,958 $ 265,585
========= ========= =========
Federal income tax expense at statutory rate $ 115,378 $ 111,285 $ 92,955
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (3,617) (3,947) (5,185)
Amortization of tax regulatory assets 693 693 693
Amortization of goodwill 13,359 13,282 13,447
Other, net 888 2,556 (1,216)
--------- --------- ---------
Total provision for income taxes $ 126,701 $ 123,869 $ 100,694
========= ========= =========
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences $ 495,588 $ 663,294 $ 672,283
Deferred nuclear expense 126,213 128,008 132,818
Impaired generating assets 107,063 -- --
Deferred sale and leaseback costs (100,028) (106,611) (113,884)
Unamortized investment tax credits (35,341) (38,172) (40,241)
Unused alternative minimum tax credits (27,115) (71,130) (124,459)
Deferred gain for asset sale to affiliated company 46,583 -- --
Other (21,215) (7,911) (2,232)
--------- --------- ---------
Net deferred income tax liability $ 591,748 $ 567,478 $ 524,285
========= ========= =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
<PAGE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include The Cleveland
Electric Illuminating Company (Company) and its wholly owned subsidiary,
Centerior Funding Corporation (CFC). All significant intercompany
transactions have been eliminated. The Company is a wholly owned subsidiary
of FirstEnergy Corp. (FirstEnergy). FirstEnergy holds directly all of the
issued and outstanding common shares of the Company and its other principal
electric utility operating subsidiaries, Ohio Edison Company (OE) and The
Toledo Edison Company (TE). On September 1, 2000, the Company sold its
transmission assets to FirstEnergy's wholly owned subsidiary, American
Transmission Systems, Inc. (ATSI). As a result, ATSI owns and operates
FirstEnergy's major high-voltage transmission facilities and has
interconnections with other regional utilities.
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 accounting principles generally accepted in
the United States (GAAP) requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses.
REVENUES-
The Company's principal business is providing electric service to
customers in northeastern 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, 2000 or 1999, with respect to any particular
segment of the Company's customers.
The Company and TE sell substantially all of their retail
customer receivables to CFC. CFC subsequently transfers the receivables to
a trust under an asset-backed securitization agreement. The trust completed
a public sale of $150 million and private sales of $50 million of
receivables-backed investor certificates in 1996 and 2000, respectively, in
transactions that qualified for sale accounting treatment. CFC's retained
interest in the pool of receivables held by the trust (15.15% as of
December 31, 2000) is stated at fair value reflecting adjustments for
anticipated credit losses. Collections of receivables previously
transferred to the trust used to purchase new receivables from CFC during
2000 totaled approximately $2.5 billion. Expenses associated with the
factoring discount related to the sale of receivables were $13 million in
2000. As of December 31, 2000, the Company's receivables recorded on its
Consolidated Balance Sheet were reduced by $90 million due to these sales.
REGULATORY PLAN-
The PUCO approved FirstEnergy's Rate Reduction and Economic
Development Plan for the Company in January 1997. The regulatory plan was
to maintain then current base electric rates for the Company through
December 31, 2005. At the end of the regulatory plan period, the Company's
base rates were to be reduced by $217 million (approximately 15 percent
below then current levels). The regulatory plan also revised the Company's
fuel cost recovery method such that the Company's fuel rate would be frozen
through the regulatory plan period, subject to limited periodic
adjustments. As part of the regulatory plan, transition rate credits were
implemented for customers, which were expected to reduce operating revenues
for the Company by approximately $280 million during the regulatory plan
period. The regulatory plan was terminated at the end of 2000 concurrent
with the implementation of the FirstEnergy transition plan as described
further below.
In July 1999, Ohio's electric utility restructuring legislation,
which allowed Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the
legislation provides for a five percent reduction on the generation portion
of residential customers' bills and the opportunity to recover transition
costs, including regulatory assets, from January 1, 2001 through
December 31, 2005. The period for the recovery of regulatory assets only
can be extended up to December 31, 2010. The PUCO was authorized to
determine the level of transition cost recovery, as well as the recovery
period for the regulatory assets portion of those costs, in considering
each Ohio electric utility's transition plan application.
FirstEnergy, on behalf of its Ohio electric utility operating
companies -- the Company, OE and TE -- filed its transition plan under
Ohio's new electric utility restructuring law in late 1999. The filing also
included additional information on FirstEnergy's plans to turn over
control, and perhaps ownership, of its transmission assets to the Alliance
Regional Transmission Organization. The transition plan itemized, or
unbundled, the current price of electricity into its component
elements -- including generation, transmission, distribution and transition
charges. As required by the PUCO's rules, FirstEnergy's transition plan
also included its proposals on corporate separation of its regulated and
unregulated operations, operational and technical support changes needed to
accommodate customer choice, an education program to inform customers of
their options under the new law, and how FirstEnergy's transmission system
will be operated to ensure access to all users. Customer prices would be
frozen through a five-year market development period (2001-2005), except
for certain limited statutory exceptions including the five percent
reduction in the price of generation for residential customers. The plan
proposed recovery of generation-related transition costs of approximately
$1.9 billion ($1.6 billion, net of deferred income taxes) and transition
costs related to regulatory assets aggregating approximately $1.9 billion
($1.4 billion, net of deferred income taxes).
On July 19, 2000, the PUCO approved FirstEnergy's transition plan
as modified by a settlement agreement with major parties to the transition
plan. Major parties to the settlement agreement included the PUCO staff, the
Ohio Consumers' Counsel, the Industrial Energy Users-Ohio, certain power
marketers and others. Major provisions of the settlement agreement consisted
of approval of recovery of transition costs in the amounts filed in the
transition plan through no later than 2008 for the Company, except where a
longer period of recovery is provided for in the settlement agreement. The
Company will also give preferred access over FirstEnergy's subsidiaries to
nonaffiliated marketers, brokers and aggregators to 400 megawatts of
generation capacity through 2005 at established prices for sales to the
Company's retail customers. The base electric rates for distribution service
for the Company under its prior regulatory plan will be extended from
December 31, 2005 through December 31, 2007. The transition rate credits for
customers under its prior regulatory plan will also be extended through the
transition cost recovery period.
The application of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71), to the nonnuclear generation business of the Company was
discontinued with the issuance of the PUCO transition plan order. The
Securities and Exchange Commission (SEC) issued interpretive guidance
regarding asset impairment measurement that concluded any supplemental
regulated cash flows such as a competitive transition charge (CTC) should be
excluded from the cash flows of assets in a portion of the business not
subject to regulatory accounting practices. If those assets are impaired, a
regulatory asset should be established if the costs are recoverable through
regulatory cash flows. Consistent with the SEC guidance $304 million of
impaired plant investments were recognized by the Company as regulatory
assets recoverable as transition costs through future regulatory cash flows.
The settlement agreement provides to the Company's customers an
additional incentive applied to the generation shopping credit of 45% for
residential customers, 30% for commercial customers and 15% for industrial
customers as reductions from their bills, when they select alternative
energy providers (the credits exceed the price the Company will be offering
to electricity suppliers relating to the 400 megawatts described above). The
amount of the incentive will serve to reduce the amortization of transition
costs during the market development period and will be recovered over the
remaining transition cost recovery period. If the customer switching targets
established in the settlement agreement are not achieved by the end of 2005,
the transition cost recovery periods could be shortened for the Company to
reduce recovery by as much as $170 million, but any such adjustment would be
computed on a class-by-class and pro-rata basis.
All of the Company's regulatory assets will continue to be
recovered under provisions of the Ohio transition plan. The Company
recognized a fair value purchase accounting adjustment to reduce nuclear
plant by $1.71 billion in connection with the 1997 FirstEnergy merger; that
fair value adjustment recognized for financial reporting purposes satisfied
the $1.4 billion asset reduction commitment contained in the regulatory
plan. For regulatory purposes, the Company recognized the applicable
accelerated amortization over the period that its rate plan was in effect.
Application of SFAS 71 was discontinued in 1997 with respect to
the Company's nuclear operations and in mid-2000, as discussed above, with
respect to the Company's nonnuclear generation business. The Company's net
assets included in utility plant relating to operations for which the
application of SFAS 71 was discontinued were $1.556 billion as of
December 31, 2000.
UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction (except
for the Company's nuclear generating units which were adjusted to fair
value), including payroll and related costs such as taxes, employee
benefits, administrative and general costs, and interest costs.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in
service. The annualized composite rate was approximately 3.4% in 2000, 1999
and 1998.
Annual depreciation expense includes approximately $11.7 million
for future decommissioning costs applicable to the Company's ownership
interests in three nuclear generating units. Annual decommissioning costs
will increase by approximately $17 million from implementing the Company's
transition plan in 2001. The Company's future decommissioning costs reflect
the 1999 increase in its ownership interests related to the exchange of
certain generating assets with Duquesne Light Company. The Company's share
of the future obligation to decommission these units is approximately
$606 million in current dollars and (using a 4.0% escalation rate)
approximately $1.6 billion in future dollars. The estimated obligation and
the escalation rate were developed based on site specific studies. Payments
for decommissioning are expected to begin in 2016, when actual
decommissioning work begins. The Company has recovered approximately
$134 million for decommissioning through its electric rates from customers
through December 31, 2000. The Company has also recognized an estimated
liability of approximately $9.0 million related to decontamination and
decommissioning of nuclear enrichment facilities operated by the United
States Department of Energy, as required by the Energy Policy Act of 1992.
The Financial Accounting Standards Board (FASB) issued a proposed
accounting standard for nuclear decommissioning costs in 1996. If the
standard is adopted as proposed: (1) annual provisions for decommissioning
could change; (2) the net present value of estimated decommissioning costs
could be recorded as a liability; and (3) income from the external
decommissioning trusts could be reported as investment income. The FASB
subsequently expanded the scope of the proposed standard to include other
closure and removal obligations related to long-lived assets. A final
pronouncement is expected in the second quarter of 2001 and is anticipated
to be implemented on January 1, 2002.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, together with TE and OE and its wholly owned
subsidiary, Pennsylvania Power Company (Penn), own and/or lease, as tenants
in common, various power generating facilities. Each of the companies is
obligated to pay a share of the costs associated with any jointly owned
facility in the same proportion as its interest. The Company's portion of
operating expenses associated with jointly owned facilities is included in
the corresponding operating expenses on the Consolidated Statements of
Income. The amounts reflected on the Consolidated Balance Sheet under
utility plant at December 31, 2000 include the following:
Utility Accumulated Construction Ownership/
Plant Provision for Work in Leasehold
Generating Units in Service Depreciation Progress Interest
- ------------------------------------------------------------------------
(In millions)
W. H. Sammis Unit 7 $ 181.8 $120.1 $ 0.2 31.20%
Bruce Mansfield
Units 1, 2 and 3 72.9 31.2 -- 20.42%
Beaver Valley Unit 2 1.7 0.3 3.8 24.47%
Davis-Besse 210.1 22.0 3.3 51.38%
Perry 617.5 107.9 10.7 44.85%
- ------------------------------------------------------------------------
Total $1,084.0 $281.5 $18.0
========================================================================
The Bruce Mansfield Plant is being leased through a sale and
leaseback transaction (see Note 2) and the above-related amounts represent
construction expenditures subsequent to the transaction.
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.
INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and
accounting purposes. Investment tax credits, which were deferred when
utilized, are being amortized over the recovery period of the related
property. The liability method is used to account for deferred income
taxes. Deferred income tax liabilities related to tax and accounting basis
differences are recognized at the statutory income tax rates in effect when
the liabilities are expected to be paid. Alternative minimum tax credits of
$27 million, which may be carried forward indefinitely, are available to
reduce future federal income taxes. The Company is included in
FirstEnergy's consolidated federal income tax return. The consolidated tax
liability is allocated on a "stand-alone" company basis, with the Company
recognizing any tax losses or credits it contributed to the consolidated
return.
RETIREMENT BENEFITS-
FirstEnergy's trusteed, noncontributory defined benefit pension
plan covers almost all of the Company's full-time employees. Upon
retirement, employees receive a monthly pension based on length of service
and compensation. The Company uses the projected unit credit method for
funding purposes and was not required to make pension contributions during
the three years ended December 31, 2000. The assets of the FirstEnergy
pension plan consist primarily of common stocks, United States government
bonds and corporate bonds.
The Company provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory
insurance. Health care benefits, which include certain employee deductibles
and copayments, are also available to retired employees, their dependents
and, under certain circumstances, their survivors. The Company pays
insurance premiums to cover a portion of these benefits in excess of set
limits; all amounts up to the limits are paid by the Company. The Company
recognizes the expected cost of providing other postretirement benefits to
employees and their beneficiaries and covered dependents from the time
employees are hired until they become eligible to receive those benefits.
The following sets forth the funded status of the plans and
amounts recognized on FirstEnergy's Consolidated Balance Sheets as of
December 31:
Other
Pension Benefits Postretirement Benefits
---------------- ------------------------
2000 1999 2000 1999
- -------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of
January 1 $1,394.1 $1,500.1 $ 608.4 $ 601.3
Service cost 27.4 28.3 11.3 9.3
Interest cost 104.8 102.0 45.7 40.7
Plan amendments 41.3 -- -- --
Actuarial loss (gain) 17.3 (155.6) 121.7 (17.6)
Net increase from asset swap -- 14.8 -- 12.5
Voluntary early retirement
program expense 23.4 -- -- --
Benefits paid (102.2) (95.5) (35.1) (37.8)
- -------------------------------------------------------------------------
Benefit obligation as of
December 31 1,506.1 1,394.1 752.0 608.4
- -------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets
as of January 1 1,807.5 1,683.0 4.9 3.9
Actual return on plan assets 0.7 220.0 (0.2) 0.6
Company contribution -- -- 18.3 0.4
Benefits paid (102.2) (95.5) -- --
- -------------------------------------------------------------------------
Fair value of plan assets as
of December 31 1,706.0 1,807.5 23.0 4.9
- -------------------------------------------------------------------------
Funded status of plan 199.9 413.4 (729.0) (603.5)
Unrecognized actuarial loss
(gain) (90.9) (303.5) 147.3 24.9
Unrecognized prior service
cost 93.1 57.3 20.9 24.1
Unrecognized net transition
obligation (asset) (2.1) (10.1) 110.9 120.1
- -------------------------------------------------------------------------
Prepaid (accrued) benefit
cost $ 200.0 $ 157.1 $(449.9) $(434.4)
=========================================================================
Company's share of accrued
benefit cost $ (34.6) $ (39.9) $(188.8) $(179.0)
=========================================================================
Assumptions used as of
December 31:
Discount rate 7.75% 7.75% 7.75% 7.75%
Expected long-term return
on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
FirstEnergy's net pension and other postretirement benefit
costs for the three years ended December 31, 2000 were computed as
follows:
Other
Pension Benefits Postretirement Benefits
-------------------- -----------------------
2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------
(In millions)
Service cost $ 27.4 $ 28.3 $ 25.0 $11.3 $ 9.3 $ 7.5
Interest cost 104.8 102.0 92.5 45.7 40.7 37.6
Expected return on
plan assets (181.0) (168.1) (152.7) (0.5) (0.4) (0.3)
Amortization of
transition
obligation (asset) (7.9) (7.9) (8.0) 9.2 9.2 9.2
Amortization of prior
service cost 5.7 5.7 2.3 3.2 3.3 (0.8)
Recognized net
actuarial loss
(gain) (9.1) -- (2.6) -- -- --
Voluntary early
retirement program
expense 17.2 -- -- -- -- --
- -------------------------------------------------------------------------
Net benefit cost $ (42.9) $ (40.0) $ (43.5) $68.9 $62.1 $53.2
=========================================================================
Company's share of
total plan costs $ (5.3) $ (14.4) $ (2.7) $21.3 $22.0 $14.5
- -------------------------------------------------------------------------
The FirstEnergy plan's health care trend rate assumption is 7.2%
in 2001, 7.0% in 2002 and 6.5% in 2003, trending to 5.0%-5.5% in later
years. Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plan. An increase in the health
care trend rate assumption by one percentage point would increase the total
service and interest cost components by $7.5 million and the postretirement
benefit obligation by $94.4 million. A decrease in the same assumption by
one percentage point would decrease the total service and interest cost
components by $8.5 million and the postretirement benefit obligation by
$111.0 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and interest charges
include transactions with TE, OE, Penn and ATSI. Primary transactions
include purchased power and transmission facilities rent expenses of $15.0
million from ATSI starting in 2000. CFC serves as the transferor in
connection with the accounts receivable securitization for the Company and
TE.
The Company is buying 150 megawatts of TE's Beaver Valley Unit 2
leased capacity entitlement. Purchased power expense for this transaction
was $104.0 million, $104.3 million and $98.5 million in 2000, 1999 and
1998, respectively. This purchase is expected to continue through the end
of the lease period. (See Note 2.)
Fuel and purchased power expenses on the Consolidated Statements
of Income include the total costs of power purchased from TE of
$106.8 million, $106.1 million and $104.7 million in 2000, 1999 and 1998,
respectively.
FirstEnergy and, prior to 1999, the Centerior Service Company
(CSC), a wholly owned subsidiary of FirstEnergy, provides support services
at cost to the Company and other affiliated companies, for which the
Company was billed $97.9 million in 2000 and $109.1 million in 1999 by
FirstEnergy, and $80.6 million in 1998 by CSC.
SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial maturity
of three months or less are reported as cash equivalents on the
Consolidated Balance Sheets. The Company reflects temporary cash
investments at cost, which approximates their fair market value. Noncash
financing and investing activities included capital lease transactions
amounting to $52.0 million, $26.2 million and $32.3 million in 2000, 1999
and 1998, respectively.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the
Consolidated Balance Sheets at cost, which approximates their fair market
value. The following sets forth the approximate fair value and related
carrying amounts of all other long-term debt, preferred stock subject to
mandatory redemption and investments other than cash and cash equivalents
as of December 31:
2000 1999
- --------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------------
(In millions)
Long-term debt $2,563 $2,655 $2,738 $2,711
Preferred stock $ 107 $ 105 $ 150 $ 139
Investments other than cash
and cash equivalents:
Debt securities
- (Maturing in more than
10 years) $ 585 $ 568 $ 517 $ 476
All other 202 210 193 200
- ---------------------------------------------------------------------
$ 787 $ 778 $ 710 $ 676
====================================================================
The fair values of long-term debt and preferred stock subject to
mandatory redemption reflect the present value of the cash outflows
relating to those securities based on the current call price, the yield to
maturity or the yield to call, as deemed appropriate at the end of each
respective year. The yields assumed were based on securities with similar
characteristics offered by a corporation with credit ratings similar to the
Company's ratings.
The fair value of investments other than cash and cash
equivalents represent cost (which approximates fair value) or the present
value of the cash inflows based on the yield to maturity. The yields
assumed were based on financial instruments with similar characteristics
and terms. Investments other than cash and cash equivalents include
decommissioning trust investments. Unrealized gains and losses applicable
to the decommissioning trusts have been recognized in the trust investment
with corresponding changes to the decommissioning liability. The Company
has no securities held for trading purposes.
REGULATORY 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 will continue to be recovered
from customers under the Company's transition plan. Based on that plan, the
Company continues to bill and collect cost-based rates for its transmission
and distribution services, which will remain regulated; accordingly, it is
appropriate that the Company continues the application of SFAS 71 to those
operations. The application of SFAS 71 to the Company's nonnuclear
generation business was discontinued effective with the PUCO's approval of
FirstEnergy's transition plan. All generating plant investments were
reviewed for impairment due to the anticipated regulatory cash flows under
the transition plan. The effect of that review was reflected on the
financial statements as of June 30, 2000, with the reduction of plant
investment and the corresponding recognition of regulatory assets
recoverable through future regulatory cash flows for generating assets that
were impaired of approximately $304 million for the Company.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2000 1999
- ------------------------------------------------------------------
(In millions)
Nuclear unit expenses $ 276.1 $ 287.1
Customer receivables for future income
taxes 18.1 23.0
Rate stabilization program deferrals 251.7 263.9
Sale and leaseback costs (131.9) (136.4)
Loss on reacquired debt 70.5 75.9
Impaired generating assets 304.3 --
Other 27.3 26.3
- -------------------------------------------------------------------
Total $ 816.1 $ 539.8
==================================================================
2. LEASES:
The Company leases certain generating facilities, nuclear fuel,
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, 2000 were
approximately $1.2 billion, net of trust cash receipts.)
Nuclear fuel is currently financed for the Company and TE through
leases with a special-purpose corporation. As of December 31, 2000,
$142 million of nuclear fuel ($86 million for the Company) was financed
under a lease financing arrangement totaling $150 million from bank credit
arrangements. The bank credit arrangements expire in August 2001. Lease
rates are based on 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 Consolidated
Statements of Income. Such costs for the three years ended December 31,
2000 and are summarized as follows:
2000 1999 1998
- -------------------------------------------------------------------
(In millions)
Operating leases
Interest element $ 36.8 $ 38.6 $ 32.4
Other 29.8 30.7 74.4
Capital leases
Interest element 5.9 6.9 7.0
Other 37.4 41.3 36.1
- -------------------------------------------------------------------
Total rentals $109.9 $117.5 $149.9
===================================================================
The future minimum lease payments as of December 31, 2000 are:
Operating Leases
---------------------------
Capital Lease Capital
Leases Payments Trust Net
- ----------------------------------------------------------------------
(In millions)
2001 $ 41.0 $ 71.7 $ 50.2 $ 21.5
2002 28.1 76.4 70.6 5.8
2003 17.3 77.5 77.9 (0.4)
2004 10.2 55.7 28.2 27.5
2005 3.7 66.7 47.5 19.2
Years thereafter 8.4 653.8 488.7 165.1
- -----------------------------------------------------------------------
Total minimum lease
payments 108.7 $1,001.8 $763.1 $238.7
Interest portion 15.3 ======== ====== ======
- ------------------------------------
Present value of net
minimum lease payments 93.4
Less current portion 28.7
- ------------------------------------
Noncurrent portion $ 64.7
===================================
The Company and TE refinanced high-cost fixed obligations related
to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant
through a lower cost transaction in June and July 1997. In a June 1997
offering (Offering), the two companies pledged $720 million aggregate
principal amount ($575 million for the Company and $145 million for TE) of
first mortgage bonds due through 2007 to a trust as security for the
issuance of a like principal amount of secured notes due through 2007. The
obligations of the two companies under these secured notes are joint and
several. Using available cash, short-term borrowings and the net proceeds
from the Offering, the two companies invested $906.5 million
($569.4 million for the Company and $337.1 million for TE) in a business
trust, in June 1997. The trust used these funds in July 1997 to purchase
lease notes and redeem all $873.2 million 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 companies' 1987 sale and leaseback
transaction. The Shippingport capital trust arrangement effectively reduces
lease costs related to that transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for payment of
cash dividends on the Company's common stock. The 1997 FirstEnergy merger
purchase accounting adjustments included resetting the retained earnings
balance to zero at the November 8, 1997 merger date.
(B) 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 2000.
The Company has three million authorized and unissued shares of
preference stock having no par value.
(C) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions for preferred stock are as follows:
Redemption
Price Per
Series Shares Share Date Beginning
- --------------------------------------------------------------------
$ 7.35 C 10,000 $ 100 (i)
91.50 Q 10,714 1,000 (i)
90.00 S 18,750 1,000 (i)
88.00 R 50,000 1,000 December 1 2001
- --------------------------------------------------------------------
(i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are
$80.5 million in 2001, $18.0 million in 2002 and $1.0 million in each year
2003-2005.
(D) LONG-TERM DEBT-
The first mortgage indenture and its supplements, which secure
all of the 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.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
----------------------
2001 $ 56.5
2002 228.0
2003 115.0
2004 307.7
2005 300.0
----------------------
The Company's obligations to repay certain pollution control
revenue bonds are secured by several series of first mortgage bonds.
Certain pollution control revenue bonds are entitled to the benefit of an
irrevocable bank letter of credit of $48.1 million and noncancelable
municipal bond insurance policies of $112.6 million to pay principal of, or
interest on, the pollution control revenue bonds. To the extent that
drawings are made under the letter of credit, the Company is entitled to a
credit against its obligation to repay that bond. The Company pays an
annual fee of 1.375% of the amount of the letter of credit to the issuing
bank and is obligated to reimburse the bank for any drawings thereunder.
The Company and TE have letters of credit of approximately
$222 million in connection with the sale and leaseback of Beaver Valley
Unit 2 that expire in May 2002. The letters of credit are secured by first
mortgage bonds of the Company and TE in the proportion of 40% and 60%,
respectively (see Note 2).
4. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis.
As of December 31, 2000, the Company had total short-term borrowings of
$28.6 million from its affiliates with a weighted average interest rate of
approximately 6.4%.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $455 million for property additions and improvements from
2001-2005, of which approximately $103 million is applicable to 2001.
Investments for additional nuclear fuel during the 2001-2005 period are
estimated to be approximately $114 million, of which approximately
$8 million applies to 2001. During the same periods, the Company's nuclear
fuel investments are expected to be reduced by approximately $144 million
and $32 million, respectively, as the nuclear fuel is consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is
covered by a combination of private insurance and an industry retrospective
rating plan. Based on its ownership and leasehold interests in Beaver
Valley Unit 2, the Davis-Besse Station and the Perry Plant, the Company's
maximum potential assessment under the industry retrospective rating plan
(assuming the other affiliate co-owners contribute their proportionate
shares of any assessments under the retrospective rating plan) would be
$106.3 million per incident but not more than $12.1 million in any one year
for each incident.
The Company is also insured as to its respective interests in
Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the
operating company for each plant. Under these policies, up to $2.75 billion
is provided for property damage and decontamination and decommissioning
costs. The Company has also obtained approximately $255.2 million of
insurance coverage for replacement power costs for its respective interests
in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the
Company can be assessed a maximum of approximately $11.8 million for
incidents at any covered nuclear facility occurring during a policy year
which are in excess of accumulated funds available to the insurer for
paying losses.
The Company intends to maintain insurance against nuclear risks
as described above as long as it is available. To the extent that
replacement power, property damage, decontamination, decommissioning,
repair and replacement costs and other such costs arising from a nuclear
incident at any of the 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 remain at risk for such costs.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Company
with regard to air and water quality and other environmental matters. The
Company estimates additional capital expenditures for environmental
compliance of approximately $41 million, which is included in the
construction forecast provided under "Capital Expenditures" for 2001
through 2005.
The Company is required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of
the generating unit involved and/or civil or criminal penalties of up to
$27,500 for each day the unit is in violation. The Environmental Protection
Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio
that allows for compliance based on a 30-day averaging period. The Company
cannot predict what action the EPA may take in the future with respect to
the interim enforcement policy.
The Company is in compliance with the current SO2 and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of
1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using
emission allowances. NOx reductions are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants.
In September 1998, the EPA finalized regulations requiring additional NOx
reductions from the Company's Ohio and Pennsylvania facilities. The EPA's
NOx Transport Rule imposes uniform reductions of NOx emissions (an
approximate 85% reduction in utility plant NOx emissions from projected
2007 emissions) across a region of twenty-two states and the District of
Columbia, including Ohio and Pennsylvania, based on a conclusion that such
NOx emissions are contributing significantly to ozone pollution in the
eastern United States. In March 2000, the U.S. Court of Appeals for the
D.C. Circuit upheld EPA's NOx Transport Rule except as applied to the State
of Wisconsin and portions of Georgia and Missouri. By October 2000, states
were to submit revised State Implementation Plans (SIP) to comply by
May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania recently submitted a SIP that requires compliance with the NOx
budgets at the Company's Pennsylvania facilities by May 1, 2003 and Ohio
submitted a "draft" SIP that requires compliance with the NOx budgets at
the Company's Ohio facilities by May 31, 2004. A Federal Implementation
Plan accompanied the NOx Transport Rule and may be implemented by the EPA
in states which fail to revise their SIP. In another separate but related
action, eight states filed petitions with the EPA under Section 126 of the
Clean Air Act seeking reductions of NOx emissions which are alleged to
contribute to ozone pollution in the eight petitioning states. The EPA
position is that the Section 126 petitions will be adequately addressed by
the NOx Transport Program, but a December 17, 1999 rulemaking established
an alternative program which would require nearly identical 85% NOx
reductions at 392 utility plants, including the Company's Ohio and
Pennsylvania plants, by May 2003, in the event implementation of the NOx
Transport Rule is not implemented by a state. Additional Section 126
petitions were filed by New Jersey, Maryland, Delaware and the District of
Columbia in mid-1999 and are still under evaluation by the EPA. FirstEnergy
continues to evaluate its compliance plans and other compliance options.
In July 1997, the EPA promulgated changes in the National Ambient
Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS
for previously unregulated ultra-fine particulate matter. In May 1999, the
U.S. Court of Appeals found constitutional and other defects in the new
NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS
rules regulating ultra-fine particulates but found defects in the new NAAQS
rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and
will depend on the manner in which they are ultimately implemented, if at
all, by the states in which the Company operates affected facilities.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost
of compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of
1976, as amended, and the Toxic Substances Control Act of 1976, federal and
state hazardous waste regulations have been promulgated. Certain
fossil-fuel combustion waste products, such as coal ash, were exempted from
hazardous waste disposal requirements pending the EPA's evaluation of the
need for future regulation. The EPA has issued its final regulatory
determination that regulation of coal ash as a hazardous waste is
unnecessary. On April 25, 2000, the EPA announced that it will develop
national standards regulating disposal of coal ash under its authority to
regulate nonhazardous waste.
The Company has been named as a "potentially responsible party"
(PRP) at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of
1980. Allegations of disposal of hazardous substances at historical sites
and the liability involved, are often unsubstantiated and subject to
dispute. Federal law provides that all PRPs for a particular site be held
liable on a joint and several basis. The Company has accrued a liability of
$3.4 million as of December 31, 2000, based on estimates of the total costs
of cleanup, the proportionate responsibility of other PRPs for such costs
and the financial ability of other PRPs to pay. The Company believes that
waste disposal costs will not have a material adverse effect on its
financial condition, cash flows or results of operations.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results
by quarter for 2000 and 1999.
March 31, June 30, September 30, December 31,
Three Months Ended 2000 2000 2000 2000
- -------------------------------------------------------------------------
(In millions)
Operating Revenues $423.7 $470.6 $525.4 $467.3
Operating Expenses
and Taxes 336.9 383.7 396.0 380.3
- ------------------------------------------------------------------------
Operating Income 86.8 86.9 129.4 87.0
Other Income 3.4 2.9 3.8 2.5
Net Interest Charges 51.5 50.5 49.2 48.5
- ------------------------------------------------------------------------
Net Income $ 38.7 $ 39.3 $ 84.0 $ 41.0
========================================================================
Earnings on Common
Stock $ 30.9 $ 32.6 $ 80.3 $ 38.3
========================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1999 1999 1999 1999
- -------------------------------------------------------------------------
(In millions)
Operating Revenues $418.8 $481.9 $534.5 $429.7
Operating Expenses
and Taxes 337.3 375.3 395.6 362.0
- -------------------------------------------------------------------------
Operating Income 81.5 106.6 138.9 67.7
Other Income (Expense) 6.5 (1.2) 1.3 2.7
Net Interest Charges 53.1 52.8 52.2 51.8
- ------------------------------------------------------------------------
Net Income $ 34.9 $ 52.6 $ 88.0 $ 18.6
========================================================================
Earnings on Common
Stock $ 26.4 $ 44.1 $ 79.7 $ 10.4
========================================================================
Report of Independent Public 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 Cleveland Electric
Illuminating Company (an Ohio corporation and wholly owned subsidiary of
FirstEnergy Corp.) and subsidiary as of December 31, 2000 and 1999, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for each of the three years in the
period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of The Cleveland Electric
Illuminating Company and subsidiary as of December 31, 2000 and 1999, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
February 16, 2001.
22