THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
2001 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........................... 2-8
Consolidated Statements of Income.............................. 9
Consolidated Balance Sheets.................................... 10
Consolidated Statements of Capitalization...................... 11-12
Consolidated Statements of Common Stockholder's Equity......... 13
Consolidated Statements of Preferred Stock..................... 13
Consolidated Statements of Cash Flows.......................... 14
Consolidated Statements of Taxes............................... 15
Notes to Consolidated Financial Statements..................... 16-26
Report of Independent Public Accountants....................... 27
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
SELECTED FINANCIAL DATA
Nov. 8- Jan. 1-
2001 2000 1999 1998 Dec. 31, 1997 Nov. 7, 1997
- -----------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION: |
|
Operating Revenues.................... $2,076,222 $1,887,039 $1,864,954 $1,795,997 $ 254,892 | $1,537,459
========== ========== ========== ========== ========== | ==========
|
Operating Income...................... $ 395,561 $ 390,094 $ 394,766 $ 382,523 $ 50,431 | $ 315,777
========== ========== ========== ========== ========== | ==========
|
Income Before Extraordinary Item...... $ 219,044 $ 202,950 $ 194,089 $ 164,891 $ 19,290 | $ 95,191
========== ========== ========== ========== ========== | ==========
|
Net Income (Loss)..................... $ 219,044 $ 202,950 $ 194,089 $ 164,891 $ 19,290 | $ (229,247)
========== ========== ========== ========== ========== | ==========
|
Earnings (Loss) on Common Stock....... $ 193,206 $ 182,107 $ 160,565 $ 140,097 $ 19,290 | $ (274,276)
========== ========== ========== ========== ========== | ==========
|
Total Assets.......................... $5,856,106 $5,964,631 $6,208,761 $6,318,183 $6,440,284 |
========== ========== ========== ========== ========== |
|
CAPITALIZATION AT DECEMBER 31: |
Common Stockholder's Equity........... $1,082,145 $1,064,839 $ 966,616 $1,008,238 $ 950,904 |
Preferred Stock- |
Not Subject to Mandatory Redemption 141,475 238,325 238,325 238,325 238,325 |
Subject to Mandatory Redemption.... 106,288 26,105 116,246 149,710 183,174 |
Long-Term Debt........................ 2,156,322 2,634,692 2,682,795 2,888,202 3,189,590 |
---------- ----------- ---------- ---------- ---------- |
Total Capitalization.................. $3,486,230 $3,963,961 $4,003,982 $4,284,475 $4,561,993 |
========== ========== ========== ========== ========== |
CAPITALIZATION RATIOS: |
Common Stockholder's Equity............ 31.0% 26.9% 24.1% 23.5% 20.9% |
Preferred Stock- |
Not Subject to Mandatory Redemption. 4.1 6.0 6.0 5.6 5.2 |
Subject to Mandatory Redemption..... 3.0 0.6 2.9 3.5 4.0 |
Long-Term Debt......................... 61.9 66.5 67.0 67.4 69.9 |
----- ----- ----- ----- ----- |
Total Capitalization................... 100.0% 100.0% 100.0% 100.0% 100.0% |
===== ===== ===== ===== ===== |
DISTRIBUTION KILOWATT-HOUR |
DELIVERIES (Millions): |
Residential............................ 5,061 5,061 5,278 4,949 790 | 4,062
Commercial............................. 4,907 6,656 6,509 6,353 893 | 4,990
Industrial............................. 9,593 8,320 8,069 8,024 1,285 | 6,710
Other.................................. 166 167 166 165 89 | 476
------ ------ ------ ------ ----- | ------
Total ................................. 19,727 20,204 20,022 19,491 3,057 | 16,238
====== ====== ====== ====== ===== | ======
CUSTOMERS SERVED: |
Residential............................ 673,852 667,115 667,954 668,470 671,265 |
Commercial............................. 70,636 69,103 69,954 68,896 74,751 |
Industrial............................. 4,783 4,851 5,090 5,336 6,515 |
Other.................................. 292 307 223 221 278 |
------- ------- ------- ------- ------- |
Total.................................. 749,563 741,376 743,221 742,923 752,809 |
======= ======= ======= ======= ======= |
|
Number of Employees (a)................ 1,025 1,046 1,694 1,798 3,162 |
<FN>
(a) Reduction in 2000 reflects transfer of responsibility for generation operations to
FirstEnergy Corp.'s competitive services unit.
</FN>
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.
Corporate Separation
- --------------------
Beginning on January 1, 2001, Ohio customers were able to choose
their electricity suppliers as a result of legislation which restructured the
electric utility industry. That legislation required unbundling the price for
electricity into its component elements - including generation, transmission,
distribution and transition charges. Also, Ohio utilities that offer both
competitive and regulated retail electric services were required to implement a
corporate separation plan approved by the Public Utilities Commission of Ohio
(PUCO) -- one which provides a clear separation between regulated and
competitive operations. In connection with FirstEnergy's transition plan,
FirstEnergy separated its businesses into three distinct units -- a competitive
services unit, a regulated services unit and a corporate support services unit.
We are included in the regulated services unit and continue to deliver power to
homes and businesses through our existing distribution system and maintain the
"provider of last resort" (PLR) obligation under our rate plan.
As a result of the transition plan, FirstEnergy's electric utility
operating companies (EUOC) entered into power supply agreements whereby
FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation,
as well as generation from leased fossil generating facilities. FirstEnergy
Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil
generating units owned by the EUOC. We are a "full requirements" customer of FES
to enable us to meet our PLR responsibilities. We continue to provide power
directly to wholesale customers under previously negotiated contracts as well as
to alternative energy suppliers as part of our market support generation of 400
megawatts (351 megawatts committed as of December 31, 2001).
The effect on our reported results of operations during 2001 from
FirstEnergy's corporate separation plan and our sale of transmission assets to
American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in
the following tables:
Corporate Restructuring - 2001 Income Statement Effects
Increase (Decrease)
Corporate
Separation ATSI Total
---------- ---- -----
(In millions)
Operating Revenues:
Power supply agreement with FES...... $334.1 $ -- $334.1
Generating units rent................ 59.1 -- 59.1
Ground lease with ATSI............... -- 2.8 2.8
-----------------------------------------------------------------------------
Total Operating Revenues Effect...... $393.2 $ 2.8 $396.0
=============================================================================
Operating Expenses and Taxes:
Fossil fuel costs.................... $(97.6)(a) $ -- $(97.6)
Purchased power costs................ 597.4 (b) -- 597.4
Other operating costs................ (90.7)(a) 13.9 (d) (76.8)
Provision for depreciation and
amortization -- (5.9)(e) (5.9)
General taxes........................ (3.2)(c) (9.3)(e) (12.5)
Income taxes......................... (4.9) 3.4 (1.5)
-----------------------------------------------------------------------------
Total Operating Expenses Effect...... $401.0 $ 2.1 $403.1
=============================================================================
Other Income........................... $ -- $ 4.8 (f) $ 4.8
=============================================================================
(a) Transfer of fossil operations to FGCO.
(b) Purchased power from power supply agreement (PSA).
(c) Payroll taxes related to employees transferred to FGCO.
(d) Transmission services received from ATSI.
(e) Depreciation and property taxes related to transmission assets sold to ATSI.
(f) Interest on note receivable from ATSI.
Results of Operations
- ---------------------
Earnings on common stock in 2001 increased 6.1% to $193.2 million in
2001 from $182.1 million in 2000. Excluding the effects shown in the table
above, earnings on common stock increased by 7.4% in 2001 from 2000, being
favorably affected by reduced operating expenses and taxes, and lower net
interest charges, which were substantially offset by reduced operating revenues.
In 2000, earnings on common stock increased 13.4% to $182.1 million from $160.6
million primarily due to higher operating revenues and reduced depreciation and
amortization, net interest charges and preferred stock dividend requirements.
Excluding the effects shown in the table above, operating revenues
decreased by $206.8 million or 11.0% in 2001 from 2000 following a $22.1 million
increase in 2000 from the prior year. Customer choice in Ohio and the influence
of a declining national economy on our regional business activity combined to
lower operating revenues. Electric generation services provided by other
suppliers in our service area represented 12.9% of total energy delivered in
2001. Retail generation sales declined in all customer categories, resulting in
an overall 14.9% reduction in kilowatt-hour sales from the prior year. As part
of Ohio's electric utility restructuring law, the implementation of a 5%
reduction in generation charges for residential customers reduced operating
revenues by approximately $16.6 million in 2001, compared to 2000. Distribution
deliveries declined 2.4% in 2001 from the prior year, reflecting the impact of a
weaker economy that contributed to lower commercial and industrial kilowatt-hour
sales. Operating revenues were also lower in 2001 from the prior year due to the
absence of revenues associated with the low-income payment plan now administered
by the Ohio Department of Development; there was also a corresponding reduction
in other operating costs associated with that change. Revenues from
kilowatt-hour sales to wholesale customers declined $86.7 million in 2001 from
last year, with a corresponding 76.4% reduction in kilowatt-hour 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 in 2000 resulting from an 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.
Changes in KWH Sales 2001 2000
---------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (14.9)% 0.9%
Wholesale............................. (76.4)%* 77.6%
---------------------------------------------------------------------
Total Electric Generation Sales......... (26.4)% 9.8%
====================================================================
Distribution Deliveries:
Residential........................... -- % (4.1)%
Commercial and industrial............. (3.2)% 2.7%
---------------------------------------------------------------------
Total Distribution Deliveries........... (2.4)% (0.9)%
=====================================================================
* Excluding PSA kilowatt-hour sales related to restructuring.
Operating Expenses and Taxes
Total operating expenses and taxes increased by $183.7 million in
2001 and by $26.8 million in 2000 from the prior year. Excluding the effects of
restructuring, total 2001 operating expenses and taxes were $219.4 million lower
than the prior year. The following table presents changes from the prior year by
expense category excluding the impact of restructuring.
Operating Expenses and Taxes - Changes 2001 2000
---------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power...................... $(145.6) $ 4.8
Nuclear operating costs....................... (11.8) 12.9
Other operating costs......................... (7.1) 6.7
--------------------------------------------------------------------
Total operation and maintenance expenses.... (164.5) 24.4
Provision for depreciation and amortization... (20.3) (10.3)
General taxes................................. (64.8) 10.7
Income taxes.................................. 30.2 2.0
--------------------------------------------------------------------
Total operating expenses and taxes.......... $(219.4) $ 26.8
====================================================================
The following discussion excludes the effects shown in the preceding
table related to the impact of restructuring.
The decrease in fuel and purchased power costs in 2001, compared to
2000, reflects the transfer of fossil operations to FGCO, with our power
requirements being provided under the PSA. In 2000, fuel and purchased power
costs increased a moderate $4.8 million, 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 (due to additional lower-cost
nuclear generation), the expiration of an above-market coal contract and
continued improvement in coal blending strategies.
There was one less nuclear refueling outage in 2001, compared to
2000, resulting in an $11.8 million decrease in nuclear operating costs from the
prior year. In 2000, nuclear operating costs increased $12.9 million, compared
to 1999, primarily due to additional refueling outage costs and increased
ownership of the Perry Plant resulting from the Duquesne asset swap. Other
operating costs decreased $7.1 million in 2001 from the prior year reflecting a
reduction in low-income payment plan customer costs and the absence of voluntary
early retirement costs in 2001, offset in part by additional planned maintenance
work at the Bruce Mansfield Plant and the absence in 2001 of gains from the sale
of emission allowances. In 2000, other operating costs rose $6.7 million,
compared to 1999, with most of the increase resulting from additional leased
portable diesel generators 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.
Depreciation and amortization decreased by $20.3 million in 2001 from
the prior year due to new deferrals for shopping incentives under our transition
plan. In 2000, 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.
General taxes decreased by $64.8 million in 2001 from 2000 due to
reduced property taxes and other state tax changes in connection with the Ohio
electric industry restructuring. The reduction in general taxes was partially
offset by $20.1 million of new Ohio franchise taxes in 2001, which are
classified as state income taxes on the Consolidated Statements of Income.
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 continued to trend lower, decreasing by $9.9
million in 2001 and by $10.1 million in 2000, compared to the prior year. We
continued to redeem and refinance our outstanding debt and preferred stock
during 2001 -- net redemptions and refinancing activities in 2001, totaled
$137.0 million and $100.0 million, respectively, and will result in annualized
savings of $15.2 million.
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 redemptions and
the amortization of fair value adjustments recognized under purchase accounting
in 1997.
Capital Resources and Liquidity
Through net debt and preferred stock redemptions, we continued to
reduce the cost of debt and preferred stock, and improve our financial position
in 2001. During 2001, we reduced our total debt by approximately $152 million.
Our common stockholder's equity as a percentage of total capitalization
increased to 31% as of December 31, 2001 from 21% at the end of 1997. We have
reduced the average cost of outstanding debt from 8.83% in 1996 to 7.88% in
2001.
Following approval of the merger of FirstEnergy and GPU by the New
Jersey Board of Public Utilities on September 26, 2001, Standard & Poor's
upgraded our credit ratings. Following a period of review and after the
Securities and Exchange Commission's approval of the merger on October 29, 2001,
Moody's also upgraded our credit ratings. The improved credit ratings result
from FirstEnergy's new consolidated credit profile following the merger. Our
credit rating outlook from Standard & Poor's and Moody's are stable. The
following table summarizes the changes:
Credit Ratings Before and After Upgrade
Before Upgrade After Upgrade
- -------------------------------------------------------------------------------
Moody's Moody's
Standard Investors Standard Investors
& Poor's Service & Poor's Service
- ------------------------------------------------------------------------------
Corporate/Issuer BB+ Ba1 BBB Baa3
Senior Secured Debt BB+ Baa3 BBB Baa2
Preferred Stock B+ Ba3 BB+ Ba2
-----------------------------------------------------------------------------
We had about $0.7 million of cash and temporary investments and $97.7
million of short-term indebtedness as of December 31, 2001. Under our first
mortgage indenture, as of December 31, 2001, we had the capability to issue $476
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 cash requirements in 2002 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Major contractual obligations for future cash payments are
summarized in the following table:
Contractual Obligations
- ---------------------------------------------------------------------------------------------------------
There-
2002 2003 2004 2005 2006 after Total
- ---------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt................ $228 $115 $280 $300 $-- $1,584 $2,507
Short-term borrowings......... 98 -- -- -- -- -- 98
Mandatory preferred stock..... 19 1 1 1 1 102 125
Capital leases ............... 1 1 1 1 1 6 11
Operating leases*............. 6 -- 27 19 16 149 217
Unconditional fuel purchases.. 65 36 52 21 -- -- 174
- ---------------------------------------------------------------------------------------------------------
Total......................... $417 $153 $361 $342 $18 $1,841 $3,132
=========================================================================================================
<FN>
* Operating lease payments are net of capital trust receipts of $712.8 million
(see Note 2).
</FN>
Our capital spending for the period 2002-2006 is expected to be about
$392 million (excluding nuclear fuel) of which approximately $121 million
applies to 2002. Investments for additional nuclear fuel during the 2002-2006
period are estimated to be approximately $176 million, of which about $19
million relates to 2002. During the same periods, our nuclear fuel investments
are expected to be reduced by approximately $163 million and $32 million,
respectively, as the nuclear fuel is consumed.
Off balance sheet obligations primarily consist of a sale and
leaseback arrangement involving the Bruce Mansfield Plant, which are reflected
in the operating lease payments above (see Note 2 - Leases). The present value
as of December 31, 2001, of these sale and leaseback operating lease
commitments, net of trust investments, total $150 million. We sell
substantially all of our retail customer receivables, which provided $97 million
of off balance sheet financing as of December 31, 2001.
On November 29, 2001, FirstEnergy reached an agreement to sell three
of our coal-fired power plants (with an aggregate net book value of $393 million
as of December 31, 2001) to NRG Energy Inc. The sale includes our 376 MW
Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants. The net, after-tax
gain from the sale, based on the difference between the sale price of the plants
and their market price used in the Ohio restructuring transition plan, will be
credited to customers by reducing the transition cost recovery period.
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 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 - Utility Plant
and Depreciation.
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
2002 2003 2004 2005 2006 after Total Value
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than Cash
and Cash Equivalents:
Fixed Income................. $ 38 $ 48 $ 1 $ 32 $ 31 $ 503 $ 653 $ 674
Average interest rate..... 7.7% 7.6% 7.8% 7.9% 7.7% 7.2% 7.3%
- -------------------------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $228 $115 $280 $300 $1,396 $2,319 $2,435
Average interest rate .... 7.7% 7.4% 7.7% 9.5% 7.4% 7.7%
Variable rate................ $ 188 $ 188 $ 189
Average interest rate..... 2.5% 2.5%
Short-term Borrowings........ $ 98 $ 98 $ 98
Average interest rate..... 3.5% 3.5%
- -------------------------------------------------------------------------------------------------------------------
Preferred Stock.............. $ 19 $ 1 $ 1 $ 1 $ 1 $ 102 $ 125 $ 125
Average dividend rate .... 8.9% 7.4% 7.4% 7.4% 7.4% 9.0% 8.9%
- -------------------------------------------------------------------------------------------------------------------
Outlook
- -------
Our industry continues to transition to a more competitive
environment. We continue to deliver power to homes and businesses through our
existing distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. In Ohio, we
have a continuing responsibility to provide power to those customers not
choosing to receive power from an alternative energy supplier. Adopting new
approaches to regulation and experiencing new forms of competition has created
new uncertainties.
Regulatory Matters
Beginning on January 1, 2001 Ohio customers were able to choose their
electricity suppliers. Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of our customers elects to obtain power
from an alternative supplier, we reduce the customer's bill with a "generation
shopping credit," based on the regulated generation component plus an incentive,
and the customer receives a generation charge from the alternative supplier. We
have continuing responsibility to provide energy to our franchise customers as
the PLR through December 31, 2005.
The transition cost portion of rates provides for recovery of certain
amounts not otherwise recoverable in a competitive generation market (such as
regulatory assets). Transition costs are paid by all customers whether or not
they choose an alternative supplier. Under the PUCO-approved transition plan, we
assumed the risk of not recovering up to $170 million of transition revenue if
the rate of customers (excluding contracts and full-service accounts) switching
from our service to an alternative supplier does not reach 20% for any
consecutive twelve-month period by December 31, 2005 - the end of the market
development period. As of December 31, 2001, the customer-switching rate, on an
annualized basis, implies that our risk of not recovering transition revenue has
been reduced to approximately $52 million. We are 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 service area. Through December 31, 2001, approximately
351 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 December 31, 2001 we had been notified that
over 365,000 of our customers requested generation service from other authorized
suppliers, including FES, an affiliated company.
Environmental Matters
We are in compliance with the current sulfur dioxide (SO2) and
nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 5 - Environmental
Matters). We continue to evaluate our compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $27,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
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
accrued a liability of $2.9 million as of December 31, 2001, 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 flows, or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against FirstEnergy and its subsidiaries. The
most significant applicable to us are described above.
Significant Accounting Policies
- -------------------------------
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect our financial results. All of our assets are subject to
their own specific risks and uncertainties and are continually reviewed for
impairment. Assets related to the application of the policies discussed below
are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on our costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio, significant amounts of
regulatory assets have been recorded -- $874 million as of December 31, 2001. We
continually review these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future. As disclosed in Note 1 - Regulatory Plans, our full recovery of
transition costs is dependent on achieving 20% customer shopping levels in any
twelve-month period by December 31, 2005.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet been billed
through the end of the year. The determination of unbilled revenues requires
management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Recently Issued Accounting Standards
- ------------------------------------
The Financial Accounting Standards Board (FASB) approved SFAS 142,
"Goodwill and Other Intangible Assets," on June 29, 2001. Under SFAS 142,
amortization of existing goodwill will cease January 1, 2002. Instead, goodwill
will be tested for impairment at least on an annual basis, and no impairment of
goodwill is anticipated as a result of a preliminary analysis. In 2001, we
amortized about $38 million of goodwill.
In July 2001, the FASB issued Statement of Financial Accounting
Standards No. (SFAS) 143, "Accounting for Asset Retirement Obligations." The new
statement provides accounting standards for retirement obligations associated
with tangible long-lived assets, with adoption required by January 1, 2003. SFAS
143 requires that the fair value of a liability for an asset retirement
obligation be recorded in the period in which it is incurred. The associated
asset retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases resulting in a period
expense. Upon retirement, a gain or loss will be recorded if the cost to settle
the retirement obligation differs from the carrying amount. We are currently
assessing the new standard and have not yet determined the impact on our
financial statements.
In September 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The Statement also supersedes the accounting and reporting
provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results
of Operations - Reporting the Effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." Our
adoption of this Statement, effective January 1, 2002, will result in our
accounting for any future impairments or disposals of long-lived assets under
the provisions of SFAS 144, but will not change the accounting principles used
in previous asset impairments or disposals. Application of SFAS 144 is not
anticipated to have a major impact on our accounting for impairments or disposal
transactions compared to the prior application of SFAS 121 or APB 30.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES.......................................... $2,076,222 $1,887,039 $1,864,954
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power................................. 768,306 414,127 409,282
Nuclear operating costs.................................. 139,787 151,571 138,686
Other operating costs.................................... 290,945 374,818 368,103
---------- ---------- ----------
Total operation and maintenance expenses............... 1,199,038 940,516 916,071
Provision for depreciation and amortization.............. 194,717 220,915 231,225
General taxes............................................ 144,948 222,297 211,636
Income taxes............................................. 141,958 113,217 111,256
---------- ---------- ----------
Total operating expenses and taxes..................... 1,680,661 1,496,945 1,470,188
---------- ---------- ----------
OPERATING INCOME............................................ 395,561 390,094 394,766
OTHER INCOME................................................ 13,292 12,568 9,141
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES.......................... 408,853 402,662 403,907
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................... 191,695 199,444 211,842
Allowance for borrowed funds used during
construction........................................... (2,293) (2,027) (1,755)
Other interest expense (credit).......................... 32 2,295 (269)
Subsidiary's preferred stock dividend requirements....... 375 -- --
---------- ---------- ----------
Net interest charges..................................... 189,809 199,712 209,818
---------- ---------- ----------
NET INCOME.................................................. 219,044 202,950 194,089
PREFERRED STOCK DIVIDEND
REQUIREMENTS............................................. 25,838 20,843 33,524
---------- ---------- ----------
EARNINGS ON COMMON STOCK.................................... $ 193,206 $ 182,107 $ 160,565
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $4,071,134 $4,036,590
Less-Accumulated provision for depreciation.................................... 1,725,727 1,624,672
---------- ----------
2,345,407 2,411,918
---------- ----------
Construction work in progress-
Electric plant............................................................... 66,266 66,904
Nuclear fuel................................................................. 21,712 24,145
---------- ----------
87,978 91,049
---------- ----------
2,433,385 2,502,967
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2)............................................ 475,543 491,830
Nuclear plant decommissioning trusts........................................... 211,605 189,804
Long-term notes receivable from associated companies........................... 103,425 92,722
Other.......................................................................... 24,611 36,084
---------- ----------
815,184 810,440
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 296 2,855
Receivables-
Customers.................................................................... 17,706 14,748
Associated companies......................................................... 75,113 81,090
Other (less accumulated provisions of $1,015,000 and
$1,000,000, respectively, for uncollectible accounts)...................... 99,716 127,639
Notes receivable from associated companies..................................... 415 384
Materials and supplies, at average cost-
Owned........................................................................ 20,230 26,039
Under consignment............................................................ 28,533 38,673
Prepayments and other.......................................................... 31,634 59,377
---------- ----------
273,643 350,805
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 874,488 816,143
Goodwill....................................................................... 1,370,639 1,408,869
Property taxes................................................................. 80,470 64,230
Other.......................................................................... 8,297 11,177
---------- ----------
2,333,894 2,300,419
---------- ----------
$5,856,106 $5,964,631
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $1,082,145 $1,064,839
Preferred stock-
Not subject to mandatory redemption.......................................... 141,475 238,325
Subject to mandatory redemption.............................................. 6,288 26,105
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures (Note 3)..... 100,000 --
Long-term debt................................................................. 2,156,322 2,634,692
---------- ----------
3,486,230 3,963,961
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock........................... 526,630 165,696
Accounts payable-
Associated companies......................................................... 81,463 102,915
Other........................................................................ 30,332 54,422
Notes payable to associated companies.......................................... 97,704 28,586
Accrued taxes................................................................. 129,830 178,707
Accrued interest............................................................... 57,101 56,142
Other.......................................................................... 60,664 82,195
---------- ----------
983,724 668,663
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes.............................................. 637,339 591,748
Accumulated deferred investment tax credits.................................... 76,187 79,957
Nuclear plant decommissioning costs............................................ 220,798 198,997
Pensions and other postretirement benefits..................................... 231,365 227,528
Other.......................................................................... 220,463 233,777
---------- ----------
1,386,152 1,332,007
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)................................................................
---------- ----------
$5,856,106 $5,964,631
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
</FN>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
(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)........................................................... 150,183 132,877
---------- ----------
Total common stockholder's equity................................................... 1,082,145 1,064,839
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- ---------------------
2001 2000 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3C):
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
--------- --------- -------- ---------- ----------
1,624,000 1,624,000 243,917 238,325 238,325
Redemption Within One Year.............. (96,850) --
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption............................ 1,624,000 1,624,000 $243,917 141,475 238,325
========= ========= ======== ---------- ----------
Subject to Mandatory Redemption:(Note 3D):
$ 7.35 Series C...................... 70,000 80,000 101.00 $ 7,070 7,030 8,041
$91.50 Series Q....................... -- 10,716 -- -- -- 10,716
$88.00 Series R....................... -- 50,000 -- -- -- 51,128
$90.00 Series S....................... 17,750 36,500 -- -- 17,268 36,686
--------- --------- -------- ---------- ----------
87,750 177,216 7,070 24,298 106,571
Redemption Within One Year.............. (18,010) (80,466)
--------- --------- -------- ---------- ----------
Total Subject to Mandatory Redemption 87,750 177,216 $ 7,070 6,288 26,105
========= ========= ======== ---------- ----------
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY COMPANY SUBORDINATED
DEBENTURES (Note 3E):
Cumulative, $25 stated value-
Authorized 4,000,000 shares
Subject to Mandatory Redemption:
9.00%................................. 4,000,000 -- $ -- 100,000 --
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3F):
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, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
7.000% due 2002-2009............................................................. 1,790 1,820
7.420% due 2001.................................................................. -- 10,000
8.540% due 2001.................................................................. -- 3,000
8.550% due 2001.................................................................. -- 5,000
8.560% due 2001.................................................................. -- 3,500
8.680% due 2001.................................................................. -- 15,000
9.050% due 2001.................................................................. -- 5,000
9.200% due 2001.................................................................. -- 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
* 1.986% due 2015.................................................................. 39,835 39,835
7.880% due 2017.................................................................. 300,000 300,000
* 2.115% due 2018.................................................................. 72,795 72,795
* 1.650% 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............................................................ 1,609,018 1,665,548
---------- ----------
Capital lease obligations (Note 2)................................................. 6,740 93,422
---------- ----------
Net unamortized premium on debt.................................................... 54,634 63,252
---------- ----------
Long-term debt due within one year................................................. (411,770) (85,230)
---------- ----------
Total long-term debt........................................................... 2,156,322 2,634,692
---------- ----------
TOTAL CAPITALIZATION.................................................................. $3,486,230 $3,963,961
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2001 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
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, 1999....................... 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
Net income.................................. $ 219,044 219,044
=========
Cash dividends on preferred stock........... (25,838)
Cash dividends on common stock.............. (175,900)
- ------------------------------------------------------------------------------------------------------------------
<
Balance, December 31, 2001..................... 79,590,689 $931,962 $150,183
==================================================================================================================
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, 1999............ 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
Issues
9.00%........................... 4,000,000 100,000
Redemptions-
$ 7.35 Series C................. (10,000) (1,000)
$88.00 Series R................. (50,000) (50,000)
$91.50 Series Q................. (10,716) (10,716)
$90.00 Series S................. (18,750) (18,750)
Amortization of fair market
value adjustments-
$ 7.35 Series C................. (11)
$88.00 Series R................. (1,128)
$90.00 Series S................. (668)
------------------------------------------------------------------------------------------
Balance, December 31, 2001.......... 1,624,000 $238,325 4,087,750 $124,298
=========================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income....................................................... $ 219,044 $ 202,950 $194,089
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization..................... 194,717 220,915 231,225
Nuclear fuel and lease amortization............................. 30,539 37,217 33,912
Other amortization.............................................. (14,071) (11,635) (10,730)
Deferred income taxes, net...................................... 46,976 22,373 33,060
Investment tax credits, net..................................... (3,770) (3,617) (3,947)
Receivables..................................................... 30,942 (16,875) (31,544)
Materials and supplies.......................................... 15,949 (1,697) 18,818
Accounts payable................................................ (45,542) 20,817 26,525
Other........................................................... (109,289) (44,188) (11,283)
--------- --------- --------
Net cash provided from operating activities................... 365,495 426,260 480,125
--------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt.................................................. -- -- 26,355
Preferred stock................................................. 96,739 -- --
Short-term borrowings, net...................................... 69,118 -- 22,853
Redemptions and Repayments-
Preferred stock................................................. 80,466 33,464 33,464
Long-term debt.................................................. 74,230 212,771 214,405
Short-term borrowings, net...................................... -- 74,885 --
Dividend Payments-
Common stock.................................................... 175,900 84,000 198,974
Preferred stock................................................. 27,645 30,518 33,524
--------- --------- --------
Net cash used for financing activities........................ 192,384 435,638 431,159
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions................................................... 154,927 96,236 122,194
Loans to associated companies........................................ 11,117 93,106 --
Loan payments from associated companies.............................. (383) -- (53,509)
Capital trust investments............................................ (16,287) (25,426) (25,905)
Sale of assets to associated companies............................... (11,117) (197,902) --
Other................................................................ 37,413 22,129 25,336
--------- --------- --------
Net cash used for (provided from) investing activities........ 175,670 (11,857) 68,116
--------- --------- --------
Net increase (decrease) in cash and cash equivalents................. (2,559) 2,479 (19,150)
Cash and cash equivalents at beginning of year....................... 2,855 376 19,526
--------- --------- --------
Cash and cash equivalents at end of year............................. $ 296 $ 2,855 $ 376
========= ========= ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................... $ 196,001 $ 208,085 $221,360
========= ========= ========
Income taxes.................................................... $ 131,801 $ 109,212 $ 92,555
========= ========= ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property......................................... $ 72,665 $131,331 $120,725
State gross receipts............................................... 27,169 79,709 78,197
Ohio kilowatt-hour excise.......................................... 42,608 -- --
Social security and unemployment................................... 2,752 11,464 10,941
Other.............................................................. (246) (207) 1,773
--------- -------- --------
Total general taxes......................................... $ 144,948 $222,297 $211,636
========= ======== ========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal......................................................... $ 97,675 $106,986 $ 92,627
State........................................................... 17,767 959 2,129
--------- -------- --------
115,442 107,945 94,756
--------- -------- --------
Deferred, net-
Federal......................................................... 42,566 23,265 33,369
State........................................................... 4,410 (892) (309)
--------- -------- --------
46,976 22,373 33,060
--------- -------- --------
Investment tax credit amortization................................. (3,770) (3,617) (3,947)
--------- -------- --------
Total provision for income taxes............................ $ 158,648 $126,701 $123,869
========= ======== ========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income................................................... $ 141,958 $113,217 $111,256
Other income....................................................... 16,690 13,484 12,613
--------- -------- --------
Total provision for income taxes............................ $ 158,648 $126,701 $123,869
========= ======== ========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes...................... $ 377,692 $329,651 $317,958
========= ======== ========
Federal income tax expense at statutory rate....................... $ 132,192 $115,378 $111,285
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit........... 14,415 44 1,183
Amortization of investment tax credits.......................... (3,770) (3,617) (3,947)
Amortization of tax regulatory assets........................... 766 693 693
Amortization of goodwill........................................ 13,380 13,359 13,282
Other, net...................................................... 1,665 844 1,373
--------- -------- --------
Total provision for income taxes............................ $ 158,648 $126,701 $123,869
========= ======== ========
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences......................................... $ 463,344 $495,588 $663,294
Competitive transition charge...................................... 279,198 133,248 21,397
Unamortized investment tax credits................................. (29,528) (35,341) (38,172)
Unused alternative minimum tax credits............................. -- (27,115) (71,130)
Deferred gain for asset sale to affiliated company................. 49,735 46,583 --
Other.............................................................. (125,410) (21,215) (7,911)
--------- -------- --------
Net deferred income tax liability........................... $ 637,339 $591,748 $567,478
========= ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
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 subsidiaries, Centerior
Funding Corporation (CFC) and Centerior Financing Trust (CFT). All significant
intercompany transactions have been eliminated. The Company is a wholly owned
subsidiary of FirstEnergy Corp. FirstEnergy holds directly all of the issued and
outstanding common shares of its principal electric utility operating
subsidiaries, including, the Company, Ohio Edison Company (OE), The Toledo
Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central
Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and
Pennsylvania Electric Company (Penelec). JCP&L, Met-Ed and Penelec were formerly
wholly owned subsidiaries of GPU, Inc. which merged with FirstEnergy on November
7, 2001.
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 and
disclosure of contingent assets and liabilities. Actual results could differ
from these estimates.
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, 2001 or 2000, 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 private sales of
$50 million and $150 million of receivables-backed investor certificates in 2000
and 2001 respectively, in transactions that qualified for sale accounting
treatment. CFC's creditors are entitled to be satisfied first out of the
proceeds of CFC's assets. The 2001 private sale was used to repay a 1996 public
sale of $150 million of receivables-backed investor certificates which was
replaced under an amended securitization agreement. FirstEnergy's retained
interest in the pool of receivables held by the trust (34% as of December 31,
2001) is stated at fair value reflecting adjustments for anticipated credit
losses. Sensitivity analyses reflecting a 10% and 20% increase in the rate of
anticipated credit losses did not significantly affect FirstEnergy's retained
interest in the pool of receivables. Collections from receivables previously
transferred to the trust were used for the purchase of new receivables from CFC
during 2001 and totaled approximately $2.2 billion. As of December 31, 2001,
receivables recorded on the Consolidated Balance Sheets were reduced by
approximately $97 million due to the sale of $185 million of receivables to the
trust less the Company's retained interest of $88 million. The Company and TE
processed receivables for the trust and received servicing fees of approximately
$4.5 million ($3.0 million applicable to the Company) in 2001. Expenses
associated with the factoring discount related to the sale of receivables were
$12 million in 2001.
REGULATORY PLAN-
Ohio's 1999 electric utility restructuring law allowed Ohio electric
customers to select their generation suppliers beginning January 1, 2001,
provided for a five percent reduction on the generation portion of residential
customers' bills and the opportunity for utilities to recover transition costs,
including regulatory assets. Under this law, the PUCO approved FirstEnergy's
transition plan in 2000 as modified by a settlement agreement with major parties
to the transition plan, which it filed on behalf of the Company, OE and TE. The
settlement agreement included approval for recovery of the amounts of transition
costs 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 settlement also granted 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 Company's base electric rates for
distribution service under its prior regulatory plan was extended from December
31, 2005 through December 31, 2007. The transition rate credits for customers
under its prior regulatory plan was also extended through the Company's
transition cost recovery period.
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 resulted in the 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 law, and planned changes in how
FirstEnergy's transmission system will be operated to ensure access to all
users. Customer prices are frozen through a five-year market development period
(2001-2005), except for certain limited statutory exceptions including a 5%
reduction in the price of generation for residential customers.
The Company's customers electing alternative suppliers receive an
additional incentive applied to the shopping credit of 45% for residential
customers, 30% for commercial customers and 15% for industrial customers. The
amount of the incentive serves to reduce the amortization of transition costs
during the market development period and will be recovered through the extension
of the transition cost recovery period. If the customer shopping goals
established in the agreement are not achieved by the end of 2005, the transition
cost recovery period 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. Based on annualized shopping levels as of
December 31, 2001, the Company believes that the maximum potential recovery
reduction was approximately $52 million.
The application of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71),
to the Company's nonnuclear generation business was discontinued with the
issuance of the PUCO transition plan order. The Securities and Exchange
Commission (SEC) issued interpretive guidance regarding asset impairment
measurement concluding that any supplemental regulated cash flows such as a
competitive transition charge 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. Net assets included in utility plant relating to the operations for which
the application of SFAS 71 was discontinued were $1.425 billion as of December
31, 2001. All of the Company's regulatory assets are expected to continue to be
recovered under provisions of the Ohio transition plan.
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 3.2% in 2001 and 3.4% in 2000
and 1999.
Annual depreciation expense includes approximately $29.0 million for
future decommissioning costs applicable to the Company's ownership interests in
three nuclear generating units. The 2001 amounts reflected an increase of
approximately $17 million from implementing the Company's transition plan in
2001. The Company's share of the future obligation to decommission these units
is approximately $656 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 $163 million for decommissioning
through its electric rates from customers through December 31, 2001. The Company
has also recognized an estimated liability of approximately $7.6 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.
In July 2001, the Financial Accounting Standards Board issued SFAS
143, "Accounting for Asset Retirement Obligations." The new statement provides
accounting treatment for retirement obligations associated with tangible
long-lived assets with adoption required as of January 1, 2003. SFAS 143
requires the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Over time the capitalized costs are depreciated and the present value of the
asset retirement liability increases, resulting in a period expense. Upon
retirement, a gain or loss will be recorded if the costs to settle the
retirement obligation differs from the carrying amount. Under the new standard,
additional assets and liabilities relating principally to nuclear
decommissioning obligations will be recorded, the pattern of expense recognition
will change and income from the external decommissioning trust will be recorded
as investment income. The Company is currently assessing the new standard and
has not yet quantified the impact on its financial statements.
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,
2001 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........... $ 183.4 $123.9 $ -- 31.20%
Bruce Mansfield Units 1, 2 and 3 84.7 35.0 22.0 20.42%
Beaver Valley Unit 2.......... 2.3 0.5 7.1 24.47%
Davis-Besse................... 209.8 33.4 12.9 51.38%
Perry......................... 631.6 126.9 2.0 44.85%
----------------------------------------------------------------------------------------------------
Total....................... $1,111.8 $319.7 $44.0
====================================================================================================
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-
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. 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. 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.
On December 31, 2001, the GPU pension plans were merged with the FirstEnergy
plan. 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, 2001. The assets of the FirstEnergy pension plan consist primarily
of common stocks, United States government bonds and corporate bonds. The
FirstEnergy and GPU postretirement benefit plans are currently separately
maintained; the information shown below is aggregated as of December 31, 2001.
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
2001 2000 2001 2000
----------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1...... $1,506.1 $1,394.1 $ 752.0 $ 608.4
Service cost............................ 34.9 27.4 18.3 11.3
Interest cost........................... 133.3 104.8 64.4 45.7
Plan amendments......................... 3.6 41.3 -- --
Actuarial loss.......................... 123.1 17.3 73.3 121.7
Voluntary early retirement program...... -- 23.4 2.3 --
GPU acquisition......................... 1,878.3 -- 716.9 --
Benefits paid........................... (131.4) (102.2) (45.6) (35.1)
--------------------------------------------------------------------------------------------
Benefit obligation as of December 31.... 3,547.9 1,506.1 1,581.6 752.0
--------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1 1,706.0 1,807.5 23.0 4.9
Actual return on plan assets............ 8.1 0.7 12.7 (0.2)
Company contribution.................... -- -- 43.3 18.3
GPU acquisition......................... 1,901.0 -- 462.0 --
Benefits paid........................... (131.4) (102.2) (6.0) --
--------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 3,483.7 1,706.0 535.0 23.0
--------------------------------------------------------------------------------------------
Funded status of plan................... (64.2) 199.9 (1,046.6) (729.0)
Unrecognized actuarial loss (gain)...... 222.8 (90.9) 212.8 147.3
Unrecognized prior service cost......... 87.9 93.1 17.7 20.9
Unrecognized net transition obligation
(asset) -- (2.1) 101.6 110.9
--------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost.......... $ 246.5 $ 200.0 $ (714.5) $(449.9)
============================================================================================
Company's share of prepaid (accrued)
benefit cost.......................... $ (32.7) $ (34.6) $ (195.9) $(188.8)
============================================================================================
Assumptions used as of December 31:
Discount rate........................... 7.25% 7.75% 7.25% 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, 2001 were computed as follows:
Other
Pension Benefits Postretirement Benefits
---------------- ------------------------
2001 2000 1999 2001 2000 1999
-------------------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 34.9 $ 27.4 $ 28.3 $18.3 $11.3 $ 9.3
Interest cost........................... 133.3 104.8 102.0 64.4 45.7 40.7
Expected return on plan assets.......... (204.8) (181.0) (168.1) (9.9) (0.5) (0.4)
Amortization of transition obligation
(asset) (2.1) (7.9) (7.9) 9.2 9.2 9.2
Amortization of prior service cost...... 8.8 5.7 5.7 3.2 3.2 3.3
Recognized net actuarial loss (gain).... -- (9.1) -- 4.9 -- --
Voluntary early retirement program...... 6.1 17.2 -- 2.3 -- --
-------------------------------------------------------------------------------------------------------
Net benefit cost........................ $ (23.8) $ (42.9) $ (40.0) $92.4 $68.9 $62.1
=======================================================================================================
Company's share of net benefit cost..... $ (1.9) $ (5.3) $ (14.4) $12.5 $21.3 $22.0
-------------------------------------------------------------------------------------------------------
The composite health care trend rate assumption is approximately 10%
in 2002, 9% in 2003 and 8% in 2004, trending to 4%-6% 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 $14.6 million and the postretirement benefit obligation by $151.2
million. A decrease in the same assumption by one percentage point would
decrease the total service and interest cost components by $12.7 million and the
postretirement benefit obligation by $131.3 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily TE, OE, Penn, ATSI,
FirstEnergy Solutions Corp. (FES) and FirstEnergy. The Ohio transition plan, as
discussed in the "Regulatory Plan" section, resulted in the corporate
separation of FirstEnergy's regulated and unregulated operations in 2001.
Unregulated operations under FES now operate the generation businesses of the
Company, TE, OE and Penn. As a result, the Company entered into power supply
agreements (PSA) whereby FES purchases all of the Company's nuclear generation
and the generation from leased fossil generating facilities and the Company
purchases its power from FES to meet its "provider of last resort" obligations.
CFC serves as the transferor in connection with the accounts receivable
securitization for the Company and TE. The primary affiliated companies
transactions, including the
effects of the PSA beginning in 2001, the sale and leaseback of the Company's
transmission assets to ATSI in September 2000 and FirstEnergy's providing
support services at cost, are as follows:
2001 2000 1999
- --------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues with FES............... $334.1 $ -- $ --
Generating units rent with FES...... 59.1 -- --
Ground lease with ATSI.............. 7.1 4.4 --
Operating Expenses:
Purchased power under PSA........... 597.4 -- --
Purchased power from TE............. 97.0 106.8 106.1
ATSI rent expense................... 28.9 15.0 --
FirstEnergy support services........ 49.6 97.9 109.1
Other Income:
Interest income from ATSI........... 7.2 2.4 --
Interest income from FES............ 0.9 -- --
- --------------------------------------------------------------------------
The Company is buying 150 megawatts of TE's Beaver Valley Unit 2
leased capacity entitlement. Purchased power expense for this transaction was
$97.0 million, $104.0 million and $104.3 million in 2001, 2000 and 1999,
respectively. This purchase is expected to continue through the end of the lease
period (See Note 2).
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 at cost, which approximates their fair market value. Noncash
financing and investing activities included capital lease transactions amounting
to $2.1 million, $52.0 million and $26.2 million in 2001, 2000 and 1999,
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:
2001 2000
- ----------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- ----------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt................................... $2,507 $2,624 $2,563 $2,655
Preferred stock.................................. $ 125 $ 125 $ 105 $ 105
Investments other than cash and cash equivalents:
Debt securities
- Maturity (5-10 years)....................... $ 11 $ 11 $ -- $ --
- Maturity (more than 10 years)............... 568 565 585 568
All other..................................... 214 218 202 210
- ----------------------------------------------------------------------------------------------------------
$ 793 $ 794 $ 787 $ 778
==========================================================================================================
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 are expected to 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.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2001 2000
------------------------------------------------------------------------
(In millions)
Regulatory transition charge.................... $830.3 $767.9
Customer receivables for future income taxes.... 9.2 10.3
Loss on reacquired debt......................... 16.5 17.8
Other........................................... 18.5 20.1
------------------------------------------------------------------------
Total...................................... $874.5 $816.1
========================================================================
2. LEASES:
The Company leases certain generating 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, 2001 were approximately $1.1 billion, net of
trust cash receipts.)
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, 2001 are
summarized as follows:
2001 2000 1999
---------------------------------------------------------------------
(In millions)
Operating leases
Interest element.... $35.3 $ 36.8 $ 38.6
Other............... 36.4 29.8 30.7
Capital leases
Interest element.... 3.6 5.9 6.9
Other............... 19.4 37.4 41.3
---------------------------------------------------------------------
Total rentals....... $94.7 $109.9 $117.5
=====================================================================
The future minimum lease payments as of December 31, 2001 are:
Operating Leases
-----------------------------
Capital Lease Capital
Leases Payments Trust Net
------------------------------------------------------------------------
(In millions)
2002........................... $ 1.0 $ 76.4 $ 70.6 $ 5.8
2003........................... 1.0 77.5 77.9 (0.4)
2004........................... 1.0 55.7 28.1 27.6
2005........................... 1.0 66.7 47.5 19.2
2006........................... 1.0 71.3 55.2 16.1
Years thereafter............... 5.7 582.5 433.5 149.0
-----------------------------------------------------------------------
Total minimum lease payments... 10.7 $930.1 $712.8 $217.3
====== ====== ======
Interest portion............... 4.0
--------------------------------------
Present value of net minimum
lease payments............... 6.7
Less current portion........... .3
--------------------------------------
Noncurrent portion............. $ 6.4
======================================
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) STOCK COMPENSATION PLANS-
Employees of the Company participate in stock based plans
administered by FirstEnergy which include the Centerior Equity Plan (CEI Plan)
and FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan).
All options are fully vested under the CE Plan, and no further awards are
permitted. Outstanding options will expire on or before February 25, 2007. Under
the FE Plan, total awards cannot exceed 15 million shares of common stock or
their equivalent. Only stock options and restricted stock have been granted,
with vesting periods ranging from six months to seven years.
Under the Executive Deferred Compensation Plan, covered employees can
direct a portion of their Annual Incentive Award and/or Long Term Incentive
Award into an unfunded FirstEnergy Stock Account to receive vested stock units.
An additional 20% premium is received in the form of stock units based on the
amount allocated to the FirstEnergy Stock Account. Dividends are calculated
quarterly on stock units outstanding and are paid in the form of additional
stock units. Upon withdrawal, stock units are converted to FirstEnergy shares.
Payout occurs three years from the date of deferral.
The Company continues to apply APB 25, "Accounting for Stock Issued
to Employees." As required by SFAS 123, "Accounting for Stock-Based
Compensation," the Company has determined pro forma earnings as though the
Company had accounted for employee stock options under the fair value method.
The weighted average assumptions used in valuing the options and their resulting
fair values are as follows:
2001 2000 1999
- ----------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 8.3 7.6 6.4
Expected volatility......... 23.45% 21.77% 20.03%
Expected dividend yield..... 5.00% 6.68% 5.97%
Risk-free interest rate..... 4.67% 5.28% 5.97%
Fair value per option......... $4.97 $2.86 $3.42
--------------------------------------------------------------------------
The following table summarizes the pro forma effect of applying fair
value accounting to the Company's stock options.
2001 2000 1999
- ----------------------------------------------------------------------------
Earnings on Company Stock (000)
As Reported................. $193,206 $182,107 $160,565
Pro Forma................... $192,784 $181,742 $160,403
- ----------------------------------------------------------------------------
(C) PREFERRED AND PREFERENCE STOCK-
The Company's $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 2001.
The Company redeemed, pursuant to redemption provisions of its $42.40
Series T issue, all 200,000 shares outstanding on February 1, 2002 at a price of
$500 per share.
The Company has three million authorized and unissued shares of
preference stock having no par value.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions currently in effect for preferred
stock are as follows:
Redemption
Price Per
Series Shares Share
--------------------------------------------------------
$ 7.35 C 10,000 $ 100
90.00 S 17,750 1,000
--------------------------------------------------------
Annual sinking fund requirements for the next five years are $18.0
million in 2002 and $1.0 million in each year 2003-2006.
(E) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES-
CFT, a wholly owned subsidiary of the Company, issued $100 million of
9% Cumulative Trust Preferred Capital Securities in December 2001. The Company
purchased all of the Trust's Common Securities and simultaneously issued to the
Trust $103.1 million principal amount of 9% Junior Subordinated Debentures due
2031 in exchange for the proceeds that the Trust received from its sale of
Preferred and Common Securities. The sole assets of the Trust are the
Subordinated Debentures whose interest and other payment dates coincide with the
distribution and other payment dates on the Trust Securities. Under certain
circumstances, the Subordinated Debentures could be distributed to the holders
of the outstanding Trust Securities in the event the Trust is liquidated.
Beginning in December 2006, the Subordinated Debentures may be optionally
redeemed by the Company at a redemption price of $25 per Subordinated Debenture
plus accrued interest, in which event the Trust Securities will be redeemed on a
pro rata basis at $25 per share plus accumulated distributions. The Company's
obligations under the Subordinated Debentures along with the related Indenture,
Trust Agreement, Guarantee Agreement and the Agreement for expenses and
liabilities, constitute a full and unconditional guarantee by the Company of
payments due on the Preferred Securities.
(F) 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)
---------------------------------------------
2002................................. $411.4
2003................................. 196.7
2004................................. 307.7
2005................................. 300.0
2006................................. --
---------------------------------------------
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 1.00% 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, 2001, the Company had total short-term borrowings of $97.7
million from its affiliates with a weighted average interest rate of
approximately 3.5%.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$392 million for property additions and improvements from 2002-2006, of which
approximately $121 million is applicable to 2002. Investments for additional
nuclear fuel during the 2002-2006 period are estimated to be approximately $176
million, of which approximately $19 million applies to 2002. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $163 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 $382 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 $22 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. In
accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note
1, generation operations and any related additional capital expenditures for
environmental compliance are the responsibility of FirstEnergy's competitive
services business unit.
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 nineteen 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. State Implementation Plans (SIP) must comply by May 31,
2004 with individual state NOx budgets established by the EPA. Pennsylvania
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. 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 if and how they are
ultimately implemented 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. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The 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 $2.9 million as of December 31, 2001, 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.
Legal Matters
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant applicable to the Company are described above.
6. SALE OF GENERATING ASSETS:
On November 29, 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants (with an aggregate net book value of $539 million as of
December 31, 2001) totaling 2,535 MW to NRG Energy Inc. (NRG) for $1.5 billion
($1.355 billion in cash and $145 million in debt assumption). The sale includes
the 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants owned by the
Company (with an aggregate net book value of $393 million as of December 31,
2001). The net, after-tax gain from the sale, based on the difference between
the sale price of the plants and their market price used in the Ohio
restructuring transition plan, will be credited to customers by reducing the
transition cost recovery period. FirstEnergy also entered into a power purchase
agreement (PPA) with NRG. Under the terms of the PPA, NRG is obligated to sell
up to 10.5 billion kilowatt-hours of electricity annually, similar to the
average annual output of the plants, through 2005. The sale is expected to close
in mid-2002.
7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2001 and 2000.
March 31, June 30, September 30, December 31,
Three Months Ended 2001 2001 2001 2001
- -----------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.................. $516.4 $498.8 $603.3 $457.7
Operating Expenses and Taxes........ 463.0 420.2 430.0 367.4
- -----------------------------------------------------------------------------------------------------
Operating Income.................... 53.4 78.6 173.3 90.3
Other Income........................ 4.4 1.1 4.0 3.7
Net Interest Charges................ 46.2 47.2 48.4 48.0
- -----------------------------------------------------------------------------------------------------
Net Income.......................... $ 11.6 $ 32.5 $128.9 $ 46.0
=====================================================================================================
Earnings on Common Stock............ $ 5.1 $ 25.4 $122.6 $ 40.1
=====================================================================================================
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
======================================================================================================
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
subsidiaries as of December 31, 2001 and 2000, 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, 2001.
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 subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.