THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
2002 ANNUAL REPORT TO STOCKHOLDERS
The Cleveland Electric Illuminating Company (CEI) 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............................ 2-12
Consolidated Statements of Income............................... 13
Consolidated Balance Sheets..................................... 14
Consolidated Statements of Capitalization....................... 15-16
Consolidated Statements of Common Stockholder's Equity.......... 17
Consolidated Statements of Preferred Stock...................... 17
Consolidated Statements of Cash Flows........................... 18
Consolidated Statements of Taxes................................ 19
Notes to Consolidated Financial Statements...................... 20-33
Reports of Independent Accountants.............................. 34-35
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues...................... $1,835,371 $2,076,222 $1,887,039 $1,864,954 $1,795,997
========== ========== ========== ========== ==========
Operating Income........................ $ 325,146 $ 395,561 $ 390,094 $ 394,766 $ 382,523
========== ========== ========== ========== ==========
Net Income.............................. $ 155,946 $ 219,044 $ 202,950 $ 194,089 $ 164,891
========== ========== ========== ========== ==========
Earnings on Common Stock................ $ 138,556 $ 193,206 $ 182,107 $ 160,565 $ 140,097
========== ========== ========== ========== ==========
Total Assets............................ $5,935,253 $5,856,106 $5,964,631 $6,208,761 $6,318,183
========== ========== ========== ========== ==========
CAPITALIZATION AT DECEMBER 31:
Common Stockholder's Equity............. $1,226,632 $1,082,145 $1,064,839 $ 966,616 $1,008,238
Preferred Stock-
Not Subject to Mandatory Redemption.. 96,404 141,475 238,325 238,325 238,325
Subject to Mandatory Redemption...... 105,021 106,288 26,105 116,246 149,710
Long-Term Debt.......................... 1,975,001 2,156,322 2,634,692 2,682,795 2,888,202
---------- ---------- ---------- ---------- ----------
Total Capitalization.................... $3,403,058 $3,486,230 $3,963,961 $4,003,982 $4,284,475
========== ========== ========== ========== ==========
CAPITALIZATION RATIOS:
Common Stockholder's Equity............. 36.0% 31.0% 26.9% 24.1% 23.5%
Preferred Stock-
Not Subject to Mandatory Redemption.. 2.9 4.1 6.0 6.0 5.6
Subject to Mandatory Redemption...... 3.1 3.0 0.6 2.9 3.5
Long-Term Debt.......................... 58.0 61.9 66.5 67.0 67.4
----- ----- ----- ----- -----
Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
DISTRIBUTION KILOWATT-HOUR
DELIVERIES (Millions):
Residential............................. 5,370 5,061 5,061 5,278 4,949
Commercial.............................. 4,628 4,907 6,656 6,509 6,353
Industrial.............................. 8,921 9,593 8,320 8,069 8,024
Other................................... 167 166 167 166 165
------ ------ ------ ------ ------
Total................................... 19,086 19,727 20,204 20,022 19,491
====== ====== ====== ====== ======
CUSTOMERS SERVED:
Residential............................. 677,095 673,852 667,115 667,954 668,470
Commercial.............................. 71,893 70,636 69,103 69,954 68,896
Industrial.............................. 4,725 4,783 4,851 5,090 5,336
Other................................... 289 292 307 223 221
------- ------- ------- ------- -------
Total................................... 754,002 749,563 741,376 743,221 742,923
======= ======= ======= ======= =======
Number of Employees..................... 974 1,025 1,046 1,694 1,798
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. CEI continues to deliver power to homes and businesses
through its existing distribution system and maintain the "provider of last
resort" (PLR) obligations under its transition 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, and leases EUOC fossil generating
facilities. CEI is a "full requirements" customer of FES to enable it to meet
its PLR responsibilities in its respective service area.
The effect on CEI's 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
======================================================================================
<FN>
(a) Transfer of fossil operations to FirstEnergy Generation Company (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.
</FN>
Results of Operations
- ---------------------
Earnings on common stock in 2002 decreased 28.3% to $138.6 million in
2002 from $193.2 million in 2001 and $182.1 million in 2000. The earnings
decrease in 2002 primarily resulted from lower operating revenues, which was
partially offset by lower operating expenses, net interest charges and preferred
stock dividend requirements. Excluding the effects shown in the table above,
earnings on common stock increased by 7.4% in 2001 from 2000, being favorably
affected by lower operating expenses and net interest charges, which were
substantially offset by reduced operating revenues.
Operating revenues decreased $240.9 million or 11.6% in 2002 compared
with 2001. The lower revenues reflected the effects of a sluggish national
economy on our service area, shopping by Ohio customers for alternative energy
providers and decreases in wholesale revenues. Retail kilowatt-hour sales
declined by 23.9% in 2002 from the prior year, with declines in all customer
sectors (residential, commercial and industrial), resulting in a $123.0 million
reduction in generation sales revenue. Our lower generation kilowatt-hour sales
resulted primarily from customer choice in Ohio. Sales of electric generation by
alternative suppliers as a percent of total sales delivered in our franchise
area increased to 31.5% in 2002 from 12.9% in 2001, while our share of electric
generation sales in our franchise areas decreased by 18.6% compared to the prior
year. Distribution deliveries decreased 3.3% in 2002 compared with 2001, which
decreased revenues from electricity throughput by $18.9 million in 2002 from the
prior year. The lower distribution deliveries resulted from the effect that
continued sluggishness in the economy had on demand by commercial and industrial
customers which was offset in part by the additional residential demand due to
warmer summer weather. Transition plan incentives, provided to customers to
encourage switching to alternative energy providers, further reduced operating
revenues $43.4 million in 2002 from the prior year. These revenue reductions are
deferred for future recovery under our transition plan and do not materially
affect current period earnings. Sales revenues from wholesale customers
decreased by $43.8 million in 2002 compared to 2001, due to lower kilowatt-hour
sales. The reduced kilowatt-hour sales resulted from lower sales to FES
reflecting the extended outage at Davis-Besse (see Davis-Besse Restoration).
Excluding the effects shown in the table above, operating revenues
decreased by $206.8 million or 11.0% in 2001 from 2000. 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 by $86.7 million in 2001 from 2000, with a corresponding 76.4%
reduction in kilowatt-hour sales.
Changes in KWH Sales 2002 2001
---------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (23.9)% (14.9)%
Wholesale............................. (12.8)% (76.4)%
---------------------------------------------------------------------
Total Electric Generation Sales......... (18.9)% (26.4)%
=====================================================================
Distribution Deliveries:
Residential........................... 6.1% -- %
Commercial and industrial............. (6.6)% (3.2)%
---------------------------------------------------------------------
Total Distribution Deliveries........... (3.3)% (2.4)%
=====================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $170.4 million in 2002
and increased by $183.7 million in 2001 from 2000. 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 on 2001 changes.
Operating Expenses and Taxes - Changes 2002 2001
---------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power..................... $(181.2) $(145.6)
Nuclear operating costs...................... 98.7 (11.8)
Other operating costs........................ 16.2 (7.1)
---------------------------------------------------------------------
Total operation and maintenance expenses... (66.3) (164.5)
Provision for depreciation and amortization.. (53.3) (20.3)
General taxes................................ 2.9 (64.8)
Income taxes................................. (53.7) 30.2
--------------------------------------------------------------------
Total operating expenses and taxes......... $(170.4) $(219.4)
- ----------------------------------------------------------------------
Lower fuel and purchased power costs in 2002 compared to 2001,
resulted from a $177.0 million reduction in power purchased from FES, reflecting
lower kilowatt-hours purchased due to reduced kilowatt-hour sales and lower unit
prices. Nuclear operating costs increased $98.7 million in 2002, primarily due
to approximately $59.1 million of incremental Davis-Besse maintenance costs
related to its extended outage (see Davis-Besse Restoration). The $16.2 million
increase in other operating costs resulted principally from higher employee
benefit costs.
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. Nuclear operating costs decreased by
$11.8 million in 2001 from the prior year due to one less nuclear refueling
outage in 2001. 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.
Charges for depreciation and amortization decreased by $53.3 million
in 2002 from 2001 primarily due to higher shopping incentive deferrals and
tax-related deferrals under our transition plan and the cessation of goodwill
amortization ($38.2 million annually) beginning January 1, 2002, upon
implementation of Statement of Financial Accounting Standards No. (SFAS) 142
"Goodwill and Other Intangible Assets." In 2001, depreciation and amortization
decreased by $20.3 million from the prior year due to new deferrals for shopping
incentives under FirstEnergy's Ohio transition plan.
General taxes increased by $2.9 million in 2002 from 2001 principally
due to additional property taxes. In 2001, general taxes decreased by $64.8
million from 2000 as a result of 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.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $4.6
million in 2002 and by $9.9 million in 2001, compared to the prior year. We
continued to redeem and refinance outstanding debt and preferred stock during
2002 - net redemptions and refinancing activities totaled $291.8 million and
$108.7 million, respectively, and will result in annualized savings of $25.5
million.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements were $8.4 million lower in 2002,
compared to the prior year principally due to the completion of $164.7 million
in optional and sinking fund preferred stock redemptions. Premiums related to
the optional redemptions partially offset the lower dividend requirements.
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 2002. During 2002, we reduced our total debt by approximately $206 million.
Our common stockholder's equity as a percentage of total capitalization
increased to 36% as of December 31, 2002 from 21% at the end of 1997. Over the
last five years, we have reduced the average cost of outstanding debt from 8.15%
in 1997 to 7.30% in 2002.
Changes in Cash Position
As of December 31, 2002, we had $30.4 million of cash and cash
equivalents, which was principally used to redeem long-term debt in January
2003, compared with $ 0.3 million as of December 31, 2001. The major sources for
changes in these balances are summarized below.
Cash Flows from Operating Activities
Our consolidated net cash from operating activities is provided by our
regulated energy services. Net cash provided from operating activities was
$317.2 million in 2002 and $365.5 million in 2001. Cash flows provided from 2002
and 2001 operating activities are as follows:
Operating Cash Flows 2002 2001
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $319.3 $ 473.4
Working capital and other............ (2.1) (107.9)
--------------------------------------------------------------
Total............................ $317.2 $ 365.5
==============================================================
(1) Includes net income, depreciation and amortization, deferred
income taxes, investment tax credits and major noncash charges.
Cash Flows from Financing Activities
In 2002, the net cash used for financing activities of $140.1 million
primarily reflects the redemptions of debt and preferred stock shown below. CEI
received an equity contribution of $50 million from FirstEnergy that facilitated
CEI's 2002 optional preferred stock redemptions.
The following table provides details regarding new issues and
redemptions during 2002:
Securities Issued or Redeemed in 2002
-------------------------------------
(In millions)
New Issues
----------
Pollution Control Notes................... $108.7
Other, principally new financing discounts (1.7)
------------------------------------------------------------
107.0
Redemptions
-----------
First Mortgage Bonds...................... 195.0
Pollution Control Notes................... 78.7
Secured Notes............................. 33.0
Preferred Stock........................... 164.7
Other, principally redemption premiums.... 2.8
- --------------------------------------------------------------
474.2
Short-term Borrowings, Net..................... $190.9
============================================================
In 2001, net cash used for financing activities totaled $192.4
million, primarily due to payment of common stock dividends to FirstEnergy.
We had about $30.8 million of cash and temporary investments and
approximately $288.6 million of short-term indebtedness at the end of 2002. We
had the capability to issue $379.3 million of additional first mortgage bonds
(FMB) on the basis of property additions and retired bonds. We have no
restrictions on the issuance of preferred stock. At the end of 2002, our common
equity as a percentage of capitalization, including debt relating to assets held
for sale, stood at 36% compared to 31% at the end of 2001. The higher common
equity percentage in 2002 compared to 2001 resulted from net redemptions of
preferred stock and long-term debt, the additional equity investment from
FirstEnergy and the increase in retained earnings.
Cash Flows from Investing Activities
Net cash used in investing activities totaled $147 million in 2002.
The net cash used for investing resulted from property additions, which was
offset in part by a reduction of the Shippingport Capital Trust investment.
Expenditures for property additions primarily include expenditures supporting
our distribution of electricity and capital expenditures related to Davis-Besse
(see Davis-Besse Restoration).
In 2001, net cash used in investing activities totaled $176 million,
principally due to property additions and the sale of property to affiliates as
part of corporate separation and the sale to ATSI discussed above.
Our cash requirements in 2003 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. Over the next three years, we expect to meet our contractual
obligations with cash from operations. Thereafter, we expect to use a
combination of cash from operations and funds from the capital markets.
Less than 1-3 3-5 More than
Contractual Obligations Total 1 Year Years Years 5 Years
- ---------------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt.................. $2,309 $145 $580 $120 $1,464
Short-term borrowings........... 289 289 -- -- --
Preferred stock (1)............. 106 1 2 2 101
Capital leases (2).............. 10 1 2 2 5
Operating leases (2)............ 200 (2) 46 25 131
Purchases (3)................... 413 46 114 100 153
- --------------------------------------------------------------------------------------------------------------
Total...................... $3,327 $480 $744 $249 $1,854
==============================================================================================================
<FN>
(1) Subject to mandatory redemption.
(2) Operating lease payments are net of capital trust receipts of $653.9 million (see Note 2).
(3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
</FN>
Our capital spending for the period 2003-2007 is expected to be about
$312 million (excluding nuclear fuel) of which approximately $96 million applies
to 2003. Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $53 million, of which about $15 million relates to
2003. During the same periods, our nuclear fuel investments are expected to be
reduced by approximately $59 million and $28 million, respectively, as the
nuclear fuel is consumed. We sell substantially all of our retail customer
receivables, which provided $118 million of off balance sheet financing as of
December 31, 2002.
On February 22, 2002, Moody's Investors Service changed its credit
rating outlook for FirstEnergy from stable to negative. The change was based
upon a decision by the Commonwealth Court of Pennsylvania to remand to the
Pennsylvania Public Utility Commission (PPUC) for reconsideration of its
decision on the mechanism for sharing merger savings and reversed the PPUC
decisions regarding rate relief and accounting deferrals rendered in connection
with its approval of the GPU merger. On March 20, 2002, Moody's changed its
outlook for CEI from stable to negative and retained a negative outlook for
FirstEnergy based on the uncertain outcome of the Davis-Besse extended outage.
On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's
credit ratings from stable to negative citing recent developments including:
damage to the Davis-Besse reactor vessel head, the Pennsylvania Commonwealth
Court decision, and deteriorating market conditions for some sales of
FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its
rating outlook for FirstEnergy and CEI securities to negative from stable. The
revised outlook reflected the adverse impact of the unplanned Davis-Besse
outage, Fitch's judgment about NRG's financial ability to consummate the
purchase of four power plants (see Note 6 - Sale of Generating Assets) from
FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On
August 1, 2002, S&P concluded that while NRG's liquidity position added
uncertainty to FirstEnergy's sale of power plants to NRG, FirstEnergy's ratings
would not be affected. S&P found its cash flows sufficiently stable to support a
continued (although delayed) program of debt and preferred stock redemption. S&P
noted that it would continue to closely monitor our progress on various
initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's
disclosure of non-cash charges related to deferred costs in Pennsylvania,
pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina
operations), which were higher than anticipated in the third quarter of 2002.
S&P identified the restart of the Davis-Besse nuclear plant "...without
significant delay beyond April 2003..." as key to maintaining its current debt
ratings. S&P also identified other issues it would continue to monitor
including: FirstEnergy's deleveraging efforts, free cash generated during 2003,
the Jersey Central Power & Light Company rate case, successful hedging of our
short power position, and continued capture of projected merger savings. While
we anticipate being prepared to restart the Davis-Besse plant in the spring of
2003, the Nuclear Regulatory Commission (NRC) must authorize the unit's restart
following a formal inspection process prior to our returning the unit to
service. Significant delays in the planned date of Davis-Besse's return to
service or other factors (identified above) affecting the speed with which we
reduce debt could put additional pressure on our credit ratings.
Other Obligations
Obligations not included on our Consolidated Balance Sheet primarily
consist of a sale and leaseback arrangement involving the Bruce Mansfield Plant,
which is reflected in the operating lease payments disclosed above (see Note 2 -
Leases). The present value as of December 31, 2002, of this sale and leaseback
operating lease commitments, net of trust investments, total $156 million.
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced since
a significant portion of our debt has fixed interest rates, as noted in the
following table. 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 had been recognized by making
corresponding changes to the decommissioning liability, as described in Note 1 -
Utility Plant and Depreciation. In conjunction with the adoption of SFAS 143,
"Accounting for Asset Retirement Obligations," on January 1, 2003, we
reclassified unrealized gains and losses to other comprehensive income
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances
will eventually affect earnings (affecting OCI initially) based on the guidance
provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from
ratepayers the difference between the investments held in trust and their
retirement obligations. Thus, in absence of disallowed costs, there will be no
earning effect from fluctuations in their decommissioning trust balances today
or in the future. As of December 31, 2002, decommissioning trust balances
totaled $1.050 billion with $698 million held by our Ohio EUOC and the balance
held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of
equity and 49% of debt instruments.
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
2003 2004 2005 2006 2007 after Total Value
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
- -------------------------------------------------------------------------------------------------------------------
Investments other than Cash
and Cash Equivalents:
Fixed Income................. $ 48 $ 1 $ 32 $ 31 $ 25 $ 494 $ 631 $ 701
Average interest rate..... 7.8% 7.8% 8.0% 7.9% 7.7% 7.1% 7.2%
- -------------------------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $145 $280 $300 $ -- $120 $1,246 $2,091 $2,275
Average interest rate .... 7.3% 7.7% 9.5% 7.1% 7.2% 7.6%
Variable rate................ $ 218 $ 218 $ 218
Average interest rate..... 1.8% 1.8%
Short-term Borrowings........ $289 $ 289 $ 289
Average interest rate..... 1.8% 1.8%
- -------------------------------------------------------------------------------------------------------------------
Preferred Stock.............. $ 1 $ 1 $ 1 $ 1 $ 1 $ 101 $ 106 $ 113
Average dividend rate .... 7.4% 7.4% 7.4% 7.4% 7.4% 9.0% 8.9%
- -------------------------------------------------------------------------------------------------------------------
Equity Price Risk
- -----------------
Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $209
million and $208 million as of December 31, 2002 and 2001, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$21 million reduction in fair value as of December 31, 2002 (see Note 1 -
Supplemental Cash Flows Information).
Outlook
- -------
Our industry continues to transition to a more competitive
environment. In 2001, all our customers could select alternative energy
suppliers. We continue to deliver power to homes and businesses through our
existing distribution systems, which remain regulated. Customer rates have been
restructured into separate components to support customer choice. In Ohio and
Pennsylvania, we have a continuing responsibility to provide power to those
customers not choosing to receive power from an alternative energy supplier
subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have 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 Ohio 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 for our customers), and the customer receives a generation charge
from the alternative supplier. We have continuing PLR responsibility to our
franchise customers through December 31, 2005. Regulatory assets are costs which
have been authorized by the Public Utilities Commission of Ohio (PUCO), PPUC and
the Federal Energy Regulatory Commission for recovery from customers in future
periods and, without such authorization, would have been charged to income when
incurred. All of our regulatory assets are expected to continue to be recovered
under the provisions of our transition plan as discussed below. Our regulatory
assets as of December 2002 and 2001 are $939.8 million and $874.5 million,
respectively.
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
did not reach 20% for any consecutive twelve-month period by December 31, 2005 -
the end of the market development period. That goal was achieved in 2002.
Accordingly, CEI does not believe that there will be any regulatory action
reducing the recoverable transition costs.
As part of our Ohio transition plan we are obligated to supply
electricity to customers who do not choose an alternative supplier. We are also
required to provided 400 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within our service area. Our
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in our franchise area. In 2003, the total peak load
forecasted for customers electing to stay with us, including the 400 MW of low
cost supply and the load served by our affiliate is 4175 MW.
Davis-Besse Restoration
On April 30, 2002, the NRC initiated a formal inspection process at
the Davis-Besse nuclear plant. This action was taken in response to corrosion
found by FirstEnergy Nuclear Operating Company (FENOC), an affiliated company,
in the reactor vessel head near the nozzle penetration hole during a refueling
outage in the first quarter of 2002. The purpose of the formal inspection
process is to establish criteria for NRC oversight of the licensee's performance
and to provide a record of the major regulatory and licensee actions taken, and
technical issues resolved, leading to the NRC's approval of restart of the
plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, we have made
significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FENOC is also accelerating
maintenance work that had been planned for future refueling and maintenance
outages. At a meeting with the NRC in November 2002, FENOC discussed plans to
test the bottom of the reactor for leaks and to install a state-of-the-art
leak-detection system around the reactor. The additional maintenance work being
performed has expanded the previous estimates of restoration work. FENOC
anticipates that the unit will be ready for restart in the spring of 2003 after
completion of the additional maintenance work and regulatory reviews. The NRC
must authorize restart of the plant following its formal inspection process
before the unit can be returned to service. While the additional maintenance
work has delayed our plans to reduce post-merger debt levels we believe such
investments in the unit's future safety, reliability and performance to be
essential. Significant delays in Davis-Besse's return to service, which depends
on the successful resolution of the management and technical issues as well as
NRC approval, could trigger an evaluation for impairment of our investment in
the plant (see Significant Accounting Policies below).
The actual costs (capital and expense) associated with the extended
Davis-Besse outage (CEI's share - 51.38%) in 2002 and estimated costs in 2003
are:
Costs of Davis-Besse Extended Outage 100%
--------------------------------------------------------------------
(In millions)
2002 - Actual
-------------
Capital Expenditures:
Reactor head and restart.......................... $ 63.3
Incremental Expenses (pre-tax):
Maintenance....................................... 115.0
Fuel and purchased power.......................... 119.5
Total............................................. $234.5
2003 - Estimated
----------------
Primarily operating expenses (pre-tax):
Maintenance (including acceleration of programs).. $50
Replacement power per month....................... $12-18
--------------------------------------------------------------------
Environmental Matters
We believe 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 $31,500 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 "potentially responsible parties" (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; however, federal law provides that all
PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, our proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. We have total accrued
liabilities aggregating approximately $2.9 million as of December 31, 2002.
The effects of our compliance with regard to environmental matters
could have a material adverse effect on our earnings and competitive position.
These environmental regulations affect our earnings and competitive position to
the extent we compete with companies that are not subject to such regulations
and therefore do not bear the risk of costs associated with compliance, or
failure to comply, with such regulations. We believe we are in material
compliance with existing regulations, but are unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
Significant Accounting Policies
- -------------------------------
We prepare our consolidated financial statements in accordance with
accounting principles that are 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 regularly
reviewed for impairment. Assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting those specific factors. Our more significant accounting policies are
described below.
Regulatory Accounting
CEI is 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 and Pennsylvania, a
significant amount of regulatory assets have been recorded. As of December 31,
2002, CEI's regulatory assets totaled $939.8 million. 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.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for KWH 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 KWH usage by residential, commercial and industrial customers
o KWH usage of customers receiving electricity from alternative
suppliers
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions we make to the plans, and earnings on plan assets. Such factors
may be further affected by business combinations (such as our merger with GPU,
Inc. in November 2001), which impacts employee demographics, plan experience and
other factors. Pension and OPEB costs may also be affected by changes to key
assumptions, including anticipated rates of return on plan assets, the discount
rates and health care trend rates used in determining the projected benefit
obligations and pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently available
rates of return on high-quality fixed income investments expected to be
available during the period to maturity of the pension and other postretirement
benefit obligations. Due to the significant decline in corporate bond yields and
interest rates in general during 2002, we reduced the assumed discount rate as
of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000.
Our assumed rate of return on pension plan assets considers historical
market returns and economic forecasts for the types of investments held by our
pension trusts. The market values of our pension assets have been affected by
sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000,
plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension
costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As
of December 31, 2002 the assumed return on plan assets was reduced to 9.00%
based upon our projection of future returns and pension trust investment
allocation of approximately 60% large cap equities, 10% small cap equities and
30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, we will not be required to fund of our pension plans in 2003. While
OPEB plan assets have also been affected by sharp declines in the equity market,
the impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates.
The effect on our SFAS 87 and 106 costs and liabilities from changes
in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions
-----------------------------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
-----------------------------------------------------------------------------------------------
(In millions)
Increase in Costs
-----------------
Discount rate................ Decrease by 0.25% $0.4 $0.4 $0.8
Long-term return on assets... Decrease by 0.25% 0.3 -- 0.3
Health care trend rate....... Increase by 1% na 1.0 1.0
Increase in Minimum Pension Liability
-------------------------------------
Discount rate................ Decrease by 0.25% 9.1 na 9.1
------------------------------------------------------------------------------------------------
As a result of the reduced market value of our pension plan assets, we
were required to recognize an additional minimum liability as prescribed by SFAS
87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement
Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of
$39.3 million and established a minimum liability of $52.1 million, recording an
intangible asset of $15.9 million and reducing OCI by $44.1 million (recording a
related deferred tax benefit of $31.4 million). The charge to OCI will reverse
in future periods to the
extent the fair value of trust assets exceed the accumulated benefit obligation.
The amount of pension liability recorded as of December 31, 2002 increased due
to the lower discount rate assumed and reduced market value of plan assets as of
December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87
and SFAS 106 is expected to increase by $6 million and $2 million, respectively
- - a total of $8 million in 2003 as compared to 2002.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset, is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, we recognize a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
Goodwill
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate
our goodwill for impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value including goodwill, an impairment for goodwill must be recognized
in the financial statements. If impairment were to occur we would recognize a
loss - calculated as the difference between the implied fair value of a
reporting unit's goodwill and the carrying value of the goodwill. Our annual
review was completed in the third quarter of 2002. The results of that review
indicated no impairment of goodwill. The forecasts used in our evaluations of
goodwill reflect operations consistent with our general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
our future evaluations of goodwill. As of December 31, 2002, we had
approximately $1.4 billion of goodwill.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
SFAS 143, "Accounting for Asset Retirement Obligations"
In June 2001, the FASB issued SFAS 143. 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. However,
rate-regulated entities may recognize regulatory assets or liabilities if the
criteria for such treatment are met. Upon retirement, a gain or loss would be
recorded if the cost to settle the retirement obligation differs from the
carrying amount.
We have identified applicable legal obligations as defined under the
new standard, principally for nuclear power plant decommissioning. Upon adoption
of SFAS 143 in January 2003, asset retirement costs of $173 million were
recorded as part of the carrying amount of the related long-lived asset, offset
by accumulated depreciation of $19 million. Due to the increased carrying
amount, the related long-lived assets were tested for impairment in accordance
with SFAS 144. No impairment was indicated. The asset retirement liability at
the date of adoption was $238 million. As of December 31, 2002, CEI had recorded
decommissioning liabilities of $240 million, including unrealized losses on
decommissioning trust funds of $0.4 million. The change in the estimated
liabilities resulted from changes in methodology and various assumptions,
including changes in the projected dates for decommissioning.
The cumulative effect adjustment to recognize the undepreciated asset
retirement cost and the asset retirement liability offset by the reversal of the
previously recorded decommissioning liabilities was a $155 million increase to
income ($91 million net of tax). The $0.4 million of unrealized losses ($0.2
million net of tax) included in the decommissioning liability balances as of
December 31, 2002, were offset against OCI upon adoption of SFAS 143.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities"
This statement, which was issued by the FASB in July 2002, requires
the recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." This new standard was effective for exit and disposal
activities initiated after December 31, 2002. Since it is applied prospectively,
there will be no impact upon
adoption. However, SFAS 146 could change the timing and amount of costs
recognized in connection with future exit or disposal activities.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107
and rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers
of guarantees must record the fair value of those guarantees at their inception.
This accounting guidance is applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. We do not believe that
implementation of FIN 45 will be material but we will continue to evaluate
anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation of
ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions beginning in the first
interim or annual reporting period after June 15, 2003 (our third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
We currently have transactions with entities which may fall within the
scope of this interpretation and which are reasonably possible of meeting the
definition of a VIE in accordance with FIN 46. We currently consolidate the
majority of these entities and believe we will continue to consolidate following
the adoption of FIN 46. One of these entities we are currently consolidating is
the Shippingport Capital Trust which reacquired a portion of the off-balance
sheet debt issued in connection with the sale and leaseback of our
interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85
percent interest by nonaffiliated parties and 0.34 percent equity interest by
Toledo Edison Capital Corp., an affiliated company.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (Note 1)................................. $1,835,371 $2,076,222 $1,887,039
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1)........................ 587,108 768,306 414,127
Nuclear operating costs (Note 1)......................... 238,513 139,787 151,571
Other operating costs (Note 1)........................... 307,142 290,945 374,818
---------- ---------- ----------
Total operation and maintenance expenses............... 1,132,763 1,199,038 940,516
Provision for depreciation and amortization.............. 141,427 194,717 220,915
General taxes............................................ 147,804 144,948 222,297
Income taxes............................................. 88,231 141,958 113,217
---------- ---------- ----------
Total operating expenses and taxes..................... 1,510,225 1,680,661 1,496,945
---------- ---------- ----------
OPERATING INCOME............................................ 325,146 395,561 390,094
OTHER INCOME (Note 1)....................................... 15,971 13,292 12,568
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES.......................... 341,117 408,853 402,662
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................... 179,140 191,695 199,444
Allowance for borrowed funds used during
construction........................................... (4,331) (2,293) (2,027)
Other interest expense................................... 1,462 32 2,295
Subsidiary's preferred stock dividend requirements....... 8,900 375 --
---------- ---------- ----------
Net interest charges..................................... 185,171 189,809 199,712
---------- ---------- ----------
NET INCOME.................................................. 155,946 219,044 202,950
PREFERRED STOCK DIVIDEND
REQUIREMENTS............................................. 17,390 25,838 20,843
---------- ---------- ----------
EARNINGS ON COMMON STOCK.................................... $ 138,556 $ 193,206 $ 182,107
========== ========== ==========
<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, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $4,045,465 $4,071,134
Less-Accumulated provision for depreciation.................................... 1,824,884 1,725,727
---------- ----------
2,220,581 2,345,407
---------- ----------
Construction work in progress-
Electric plant............................................................... 153,104 66,266
Nuclear fuel................................................................. 45,354 21,712
---------- ----------
198,458 87,978
---------- ----------
2,419,039 2,433,385
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2)............................................ 435,907 475,543
Nuclear plant decommissioning trusts........................................... 230,527 211,605
Long-term notes receivable from associated companies........................... 102,978 103,425
Other.......................................................................... 21,004 24,611
---------- ----------
790,416 815,184
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 30,382 296
Receivables-
Customers.................................................................... 11,317 17,706
Associated companies......................................................... 74,002 75,113
Other (less accumulated provisions of $1,015,000 for uncollectible accounts
at both dates)............................................................. 134,375 99,716
Notes receivable from associated companies..................................... 447 415
Materials and supplies, at average cost-
Owned........................................................................ 18,293 20,230
Under consignment............................................................ 38,094 28,533
Prepayments and other.......................................................... 4,217 31,634
---------- ----------
311,127 273,643
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 939,804 874,488
Goodwill....................................................................... 1,370,639 1,370,639
Property taxes................................................................. 79,430 80,470
Other.......................................................................... 24,798 8,297
---------- ----------
2,414,671 2,333,894
---------- ----------
$5,935,253 $5,856,106
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $1,226,632 $1,082,145
Preferred stock-
Not subject to mandatory redemption.......................................... 96,404 141,475
Subject to mandatory redemption.............................................. 5,021 6,288
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures (Note 3)..... 100,000 100,000
Long-term debt................................................................. 1,975,001 2,156,322
---------- ----------
3,403,058 3,486,230
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock........................... 388,190 526,630
Accounts payable-
Associated companies......................................................... 267,664 81,463
Other........................................................................ 14,583 30,332
Notes payable to associated companies.......................................... 288,583 97,704
Accrued taxes................................................................. 126,262 129,830
Accrued interest............................................................... 51,767 57,101
Other.......................................................................... 64,324 60,664
---------- ----------
1,201,373 983,724
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes.............................................. 659,044 637,339
Accumulated deferred investment tax credits.................................... 72,125 76,187
Nuclear plant decommissioning costs............................................ 239,720 220,798
Pensions and other postretirement benefits..................................... 171,968 231,365
Other.......................................................................... 187,965 220,463
---------- ----------
1,330,822 1,386,152
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)................................................................
---------- ----------
$5,935,253 $5,856,106
========== ==========
<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, 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(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.................................................... $ 981,962 $ 931,962
Accumulated other comprehensive loss (Note 3G)..................................... (44,051) --
Retained earnings (Note 3A)........................................................ 288,721 150,183
---------- ----------
Total common stockholder's equity................................................ 1,226,632 1,082,145
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
2002 2001 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 -- -- -- 45,071
Adjustable Series L.................... 474,000 474,000 100.00 47,400 46,404 46,404
$42.40 Series T........................ -- 200,000 -- -- -- 96,850
--------- --------- ------- ---------- ----------
974,000 1,624,000 97,900 96,404 238,325
Redemption Within One Year............... -- (96,850)
--------- --------- ------- ---------- ----------
Total Not Subject to Mandatory
Redemption............................. 974,000 1,624,000 $97,900 96,404 141,475
========= ========= ======= ---------- ----------
Subject to Mandatory Redemption (Note 3D):
$ 7.35 Series C....................... 60,000 70,000 101.00 $ 6,060 6,021 7,030
$90.00 Series S........................ -- 17,750 -- -- -- 17,268
--------- --------- ------- ---------- ----------
60,000 87,750 6,060 6,021 24,298
Redemption Within One Year............... (1,000) (18,010)
--------- --------- ------- ---------- ----------
Total Subject to Mandatory Redemption 60,000 87,750 $ 6,060 5,021 6,288
========= ========= ======= ---------- ----------
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 4,000,000 -- $ -- 100,000 100,000
========= ========= ======= ---------- ----------
LONG-TERM DEBT (Note 3F):
First mortgage bonds:
7.625% due 2002.......................................................................... -- 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............................................................. 675,000 870,000
---------- ----------
Unsecured notes:
6.000% due 2013.......................................................................... 78,700 --
* 5.580% due 2033.......................................................................... 27,700 27,700
---------- ----------
Total unsecured notes.................................................................. 106,400 27,700
---------- ----------
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
7.000% due 2003-2009............................................................. 1,760 1,790
7.850% due 2002.................................................................. -- 5,000
8.130% due 2002.................................................................. -- 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
*1.176% due 2015.................................................................. 39,835 39,835
7.880% due 2017.................................................................. 300,000 300,000
*1.180% due 2018.................................................................. 72,795 72,795
*1.550% 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
*1.300% due 2033.................................................................. 30,000 --
---------- ----------
Total secured notes............................................................ 1,527,288 1,609,018
---------- ----------
Capital lease obligations (Note 2)................................................. 6,351 6,740
---------- ----------
Net unamortized premium on debt.................................................... 47,152 54,634
---------- ----------
Long-term debt due within one year................................................. (387,190) (411,770)
---------- ----------
Total long-term debt........................................................... 1,975,001 2,156,322
---------- ----------
TOTAL CAPITALIZATION.................................................................. $3,403,058 $3,486,230
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2002 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
Accumulated
Other
Comprehensive Number Carrying Comprehensive Retained
Income of Shares Value Income (Loss) Earnings
------------- --------- ----- ------------- --------
(Dollars in thousands)
Balance, January 1, 2000....................... 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
Net income.................................. $155,946 155,946
Minimum liability for unfunded retirement
benefits, net of $(31,359,000) of
income taxes.............................. (44,051) (44,051)
--------
Comprehensive income........................ $111,895
========
Equity contribution from parent............. 50,000
Cash dividends on preferred stock........... (12,665)
Preferred stock redemption premiums......... (4,743)
- -----------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002..................... 79,590,689 $981,962 $(44,051) $ 288,721
=================================================================================================================
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, 2000.......... 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
Redemptions
$ 7.56 Series B............... (450,000) (45,071)
$42.40 Series T............... (200,000) (96,850)
$ 7.35 Series C............... (10,000) (1,000)
$90.00 Series S............... (17,750) (17,010)
Amortization of fair market
value adjustments-
$7.35 Series C............... (9)
$90.00 Series S............... (258)
----------------------------------------------------------------------------------------
Balance, December 31, 2002........ 974,000 $96,404 4,060,000 $106,021
========================================================================================
<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, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income........................................................... $155,946 $ 219,044 $ 202,950
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization..................... 141,427 194,717 220,915
Nuclear fuel and lease amortization............................. 21,044 30,539 37,217
Other amortization.............................................. (15,008) (14,071) (11,635)
Deferred income taxes, net...................................... 19,973 46,976 22,373
Investment tax credits, net..................................... (4,062) (3,770) (3,617)
Receivables..................................................... (27,159) 30,942 (16,875)
Materials and supplies.......................................... (7,624) 15,949 (1,697)
Accounts payable................................................ 47,147 (45,542) 20,817
Other (Note 7).................................................. (14,529) (109,289) (44,188)
-------- --------- ---------
Net cash provided from operating activities................... 317,155 365,495 426,260
-------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt.................................................. 106,981 -- --
Preferred stock................................................. -- 96,739 --
Short-term borrowings, net...................................... 190,879 69,118 --
Equity contributions from parent................................ 50,000 -- --
Redemptions and Repayments-
Preferred stock................................................. (164,674) (80,466) (33,464)
Long-term debt.................................................. (309,480) (74,230) (212,771)
Short-term borrowings, net...................................... -- -- (74,885)
Dividend Payments-
Common stock.................................................... -- (175,900) (84,000)
Preferred stock................................................. (13,782) (27,645) (30,518)
-------- --------- ---------
Net cash provided from (used for) financing activities........ (140,076) (192,384) (435,638)
-------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions................................................... (163,199) (154,927) (96,236)
Loans to associated companies........................................ -- (11,117) (93,106)
Loan payments from associated companies.............................. 415 383 --
Capital trust investments............................................ 39,636 16,287 25,426
Sale of assets to associated companies............................... -- 11,117 197,902
Other (Note 7)....................................................... (23,845) (37,413) (22,129)
-------- --------- ---------
Net cash provided from (used for) investing activities........ (146,993) (175,670) 11,857
-------- --------- ---------
Net increase (decrease) in cash and cash equivalents................. 30,086 (2,559) 2,479
Cash and cash equivalents at beginning of year....................... 296 2,855 376
-------- --------- ---------
Cash and cash equivalents at end of year............................. $ 30,382 $ 296 $ 2,855
======== ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................... $186,040 $ 196,001 $ 208,085
======== ========= =========
Income taxes.................................................... $121,668 $ 131,801 $ 109,212
======== ========= =========
<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, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property......................................... $ 77,516 $ 72,665 $131,331
State gross receipts*.............................................. -- 27,169 79,709
Ohio kilowatt-hour excise*......................................... 66,775 42,608 --
Social security and unemployment................................... 3,478 2,752 11,464
Other.............................................................. 35 (246) (207)
-------- --------- --------
Total general taxes......................................... $147,804 $ 144,948 $222,297
======== ========= ========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal......................................................... $ 72,467 $ 97,675 $106,986
State........................................................... 13,466 17,767 959
-------- --------- --------
85,933 115,442 107,945
-------- --------- --------
Deferred, net-
Federal......................................................... 12,592 42,566 23,265
State........................................................... 7,381 4,410 (892)
-------- --------- --------
19,973 46,976 22,373
-------- --------- --------
Investment tax credit amortization................................. (4,062) (3,770) (3,617)
-------- --------- --------
Total provision for income taxes............................ $101,844 $ 158,648 $126,701
======== ========= ========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income................................................... $ 88,231 $ 141,958 $113,217
Other income....................................................... 13,613 16,690 13,484
-------- --------- --------
Total provision for income taxes............................ $101,844 $ 158,648 $126,701
======== ========= ========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes...................... $257,790 $ 377,692 $329,651
======== ========= ========
Federal income tax expense at statutory rate....................... $ 90,227 $ 132,192 $115,378
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit........... 13,551 14,415 44
Amortization of investment tax credits.......................... (4,062) (3,770) (3,617)
Amortization of tax regulatory assets........................... 753 766 693
Amortization of goodwill........................................ -- 13,380 13,359
Other, net...................................................... 1,375 1,665 844
-------- --------- --------
Total provision for income taxes............................ $101,844 $ 158,648 $126,701
======== ========= ========
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences......................................... $473,506 $ 463,344 $495,588
Competitive transition charge...................................... 269,365 279,198 133,248
Unamortized investment tax credits................................. (27,839) (29,528) (35,341)
Unused alternative minimum tax credits............................. -- -- (27,115)
Deferred gain for asset sale to affiliated company................. 43,193 49,735 46,583
Other comprehensive income......................................... (31,359) -- --
Other (Note 7)..................................................... (67,822) (125,410) (21,215)
-------- --------- --------
Net deferred income tax liability........................... $659,044 $ 637,339 $591,748
======== ========= ========
<FN>
* Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.
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 Securities and Exchange Commission (SEC), 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 the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates.
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, after
eliminating the effects of intercompany transactions. Non-majority owned
investments, including investments in limited liability companies, partnerships
and joint ventures, are accounted for under the equity method when the Company
is able to influence their financial or operating policies. Investments in
corporations resulting in voting control of 20% or more are presumed to be
equity method investments. Limited partnerships are evaluated in accordance with
SEC Staff D-46, "Accounting for Limited Partnership Investments" and American
Institute of Certified Public Accountants (AICPA) Statement of Position (SOP)
78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to
5 percent threshold for the presumption of influence. For all remaining
investments (excluding those within the scope of SFAS 115) the Company applies
the cost method.
(B) 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, 2002 or 2001, with respect to any particular segment of the
Company's customers.
The Company and TE sell substantially all of their retail customers'
receivables to CFC. CFC subsequently transfers the receivables to a trust (a
SFAS 140 "qualified special purpose entity") under an asset-backed
securitization agreement. Transfers are made in return for an interest in the
trust (41% as of December 31, 2002), which is stated at fair value, reflecting
adjustments for anticipated credit losses. The average collection period for
billed receivables is 28 days. Given the short collection period after billing,
the fair value of CFC's interest in the trust approximates the stated value of
its retained interest in underlying receivables after adjusting for anticipated
credit losses. Accordingly, subsequent measurements of the retained interest
under SFAS 115 (as an available-for-sale financial instrument) result in no
material change in value. Sensitivity analyses reflecting 10% and 20% increases
in the rate of anticipated credit losses would not have significantly affected
the Company's retained interest in the pool of receivables through the trust. Of
the $272 million sold to the trust and outstanding as of December 31, 2002, the
Company had a retained interest in $111 million of the receivables included as
other receivables on the Consolidated Balance Sheets. Accordingly, receivables
recorded on the Consolidated Balance Sheets were reduced by approximately $161
million due to these sales. Collections of receivables previously transferred to
the trust and used for the purchase of new receivables from CFC during 2002,
totaled approximately $2.2 billion. The Company processed receivables for the
trust and received servicing fees of approximately $2.5 million in 2002.
Expenses associated with the factoring discount related to the sale of
receivables were $4.7 million in 2002.
(C) REGULATORY PLAN-
In July 1999, Ohio's electric utility restructuring legislation, which
allowed Ohio electric customers to select their generation suppliers beginning
January 1, 2001, was signed into law. Among other things, the legislation
provided for a 5% reduction on the generation portion of residential customers'
bills and the opportunity to recover transition costs,
including regulatory assets, from January 1, 2001 through December 31, 2005
(market development period). The period for the recovery of regulatory assets
only can be extended up to December 31, 2010. The PUCO was authorized to
determine the level of transition cost recovery, as well as the recovery period
for the regulatory assets portion of those costs, in considering each Ohio
electric utility's transition plan application.
In July 2000, the PUCO approved FirstEnergy's transition plan for the
the Company, OE and TE as modified by a settlement agreement with major parties
to the transition plan. The application of SFAS 71, "Accounting for the Effects
of Certain Types of Regulation" to the Company's nonnuclear generation business
was discontinued with the issuance of the PUCO transition plan order, as
described further below. Major provisions of the settlement agreement consisted
of approval of recovery of generation-related transition costs as filed of $1.6
billion net of deferred income taxes and transition costs related to regulatory
assets as filed of $1.4 billion net of deferred income taxes, with recovery
through no later than 2008 for the Company, except where a longer period of
recovery is provided for in the settlement agreement. The generation-related
transition costs include $0.2 billion, net of deferred income taxes of impaired
generating assets recognized as regulatory assets as described further below,
$0.4 billion, net of deferred income taxes of above market operating lease costs
and $0.5 billion, net of deferred income taxes of additional plant costs that
were reflected on the Company's regulatory financial statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 400 megawatts (MW) of generation capacity through 2005 at
established prices for sales to the Company's retail customers. Customer prices
are frozen through the five-year market development period except for certain
limited statutory exceptions, including the 5% reduction referred to above. In
February 2003, the Company was authorized increases in annual revenues
aggregating approximately $4 million to recover its higher tax costs resulting
from the Ohio deregulation legislation.
The Company's customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
transition cost recovery period. If the customer shopping goals established in
the agreement had not been achieved by the end of 2005, the transition cost
recovery period could have been shortened for the Company to reduce recovery by
as much as $170 million. The Company achieved its required 20% customer shopping
goals in 2002. Accordingly, the Company believes that there will be no
regulatory action reducing the recoverable transition costs.
The application of SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation", (SFAS 71), has been discontinued with respect to the
Company's generation operations. The 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 $1.406 billion as of December 31, 2002.
(D) 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's accounting
policy for planned major maintenance projects is to recognize liabilities as
they are incurred.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annualized composite rate was approximately 3.4% in 2002, 3.2% in 2001 and
3.4% in 2000.
Annual depreciation expense includes approximately $29.0 million for
future decommissioning costs applicable to the Company's ownership interests in
three nuclear generating units (Beaver Valley Unit 2, Davis-Besse Unit 1 and
Perry Unit 1). The Company's share of the future obligation to decommission
these units is approximately $682 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 $192
million for decommissioning through its electric rates from customers through
December 31, 2002. The Company has also recognized an estimated liability of
approximately $6.2 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 June 2001, the Financial Accounting Standards Board issued 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. However,
rate-regulated entities may recognize a regulatory asset or liability if the
criteria for such treatment are met. Upon retirement, a gain or loss would be
recorded if the cost to settle the retirement obligation differs from the
carrying amount.
The Company has identified applicable legal obligations as defined
under the new standard, principally for nuclear power plant decommissioning.
Upon adoption of SFAS 143, asset retirement costs of $173 million were recorded
as part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $19 million. Due to the increased carrying amount,
the related long-lived assets were tested for impairment in accordance with SFAS
144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment
was indicated.
The asset retirement liability at the date of adoption will be $238
million. As of December 31, 2002, the Company had recorded decommissioning
liabilities of $240 million, including unrealized losses on decommissioning
trust funds of $0.4 million. The change in the estimated liabilities resulted
from changes in methodology and various assumptions, including changes in the
projected dates for decommissioning.
The cumulative effect adjustment to recognize the undepreciated asset
retirement cost and the asset retirement liability offset by the reversal of the
previously recorded decommissioning liabilities was a $155 million increase to
income, or $91 million net of tax. The $0.4 million of unrealized losses, $0.2
million net of tax, included in the decommissioning liability balances as of
December 31, 2002, was offset against other comprehensive income (OCI) upon
adoption of SFAS 143.
The FASB approved SFAS 142, "Goodwill and Other Intangible Assets," on
June 29, 2001. Under SFAS 142, amortization of existing goodwill ceased January
1, 2002. Instead, goodwill is tested for impairment at least on an annual basis
- - based on the results of the transition analysis and the 2002 annual analysis,
no impairment of the Company's goodwill is required. Prior to the adoption of
SFAS 142, the Company amortized about $38.2 million of goodwill annually. The
goodwill balance as of December 31, 2002 and 2001 was $1.371 billion.
The following table shows what net income would have been if goodwill
amortization had been excluded from prior periods:
2002 2001 2000
---- ---- ----
(In thousands)
Reported net income.................. $155,946 $219,044 $202,950
Add back goodwill amortization....... -- 38,230 38,170
-------- -------- --------
Adjusted net income.................. $155,946 $257,274 $241,120
======== ======== ========
(E) 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,
2002 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........... $ 179.8 $125.4 $ -- 31.20%
Bruce Mansfield Units 1, 2
and 3 ...................... 85.2 38.6 40.6 20.42%
Beaver Valley Unit 2.......... 3.9 0.4 10.7 24.47%
Davis-Besse................... 219.4 46.6 60.1 51.38%
Perry......................... 633.0 147.1 4.9 44.85%
-------------------------------------------------------------------------------------------------
Total...................... $1,121.3 $358.1 $116.3 .
====================================================================================================
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.
(F) 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.
(G) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 3B). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the fair
value method, a higher value would have been assigned to the options granted.
The weighted average assumptions used in valuing the options and their resulting
estimated fair values would be as follows:
2002 2001 2000
- --------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years). 8.1 8.3 7.6
Expected volatility.......... 23.31% 23.45% 21.77%
Expected dividend yield...... 4.36% 5.00% 6.68%
Risk-free interest rate...... 4.60% 4.67% 5.28%
Fair value per option.......... $6.45 $4.97 $2.86
-------------------------------------------------------------------------
The effects of applying fair value accounting to FirstEnergy's stock
options would not materially effect the Company's net income.
(H) 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.
(I) 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, 2002. The assets of the FirstEnergy pension plan consist primarily
of common stocks, United States government bonds and corporate bonds.
The Company provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee contributions, 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.
As a result of the reduced market value of FirstEnergy's pension plan
assets, it was required to recognize an additional minimum liability as
prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and
Postretirement Benefits," as of December 31, 2002.FirstEnergy's accumulated
benefit obligation of $3.438 billion exceeded the fair value of plan assets
($2.889 billion) resulting in a minimum pension liability of $548.6 million.
FirstEnergy eliminated its prepaid pension asset of $286.9 million ($39.3
million) and established a minimum liability of $548.6 million (Company - $52.1
million), recording an intangible asset of $78.5 million (Company - $15.9
million) and reducing OCI by $444.2 million (Company - $44.1 million) (recording
a related deferred tax asset of $312.8 million (Company - $31.4 million)). The
charge to OCI will reverse in future periods to the extent the fair value of
trust assets exceed the accumulated benefit obligation. The amount of
pension liability recorded as of December 31, 2002, increased due to the lower
discount rate and asset returns assumed as of December 31, 2002.
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
---------------- -----------------------
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1....... $3,547.9 $1,506.1 $1,581.6 $ 752.0
Service cost............................. 58.8 34.9 28.5 18.3
Interest cost............................ 249.3 133.3 113.6 64.4
Plan amendments.......................... -- 3.6 (121.1) --
Actuarial loss........................... 268.0 123.1 440.4 73.3
Voluntary early retirement program....... -- -- -- 2.3
GPU acquisition.......................... (11.8) 1,878.3 110.0 716.9
Benefits paid............................ (245.8) (131.4) (83.0) (45.6)
-------------------------------------------------------------------------------------------
Benefit obligation as of December 31..... 3,866.4 3,547.9 2,070.0 1,581.6
-------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of
January 1 3,483.7 1,706.0 535.0 23.0
Actual return on plan assets............. (348.9) 8.1 (57.1) 12.7
Company contribution..................... -- -- 37.9 43.3
GPU acquisition.......................... -- 1,901.0 -- 462.0
Benefits paid............................ (245.8) (131.4) (42.5) (6.0)
-------------------------------------------------------------------------------------------
Fair value of plan assets as of
December 31 ............................ 2,889.0 3,483.7 473.3 535.0
-------------------------------------------------------------------------------------------
Funded status of plan.................... (977.4) (64.2) (1,596.7) (1,046.6)
Unrecognized actuarial loss.............. 1,185.8 222.8 751.6 212.8
Unrecognized prior service cost.......... 78.5 87.9 (106.8) 17.7
Unrecognized net transition obligation... -- -- 92.4 101.6
-------------------------------------------------------------------------------------------
Net amount recognized.................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
===========================================================================================
Consolidated Balance Sheets
classification:
Prepaid (accrued) benefit cost........... $ (548.6) $ 246.5 $ (859.5) $ (714.5)
Intangible asset......................... 78.5 -- -- --
Accumulated other comprehensive loss..... 757.0 -- -- --
-------------------------------------------------------------------------------------------
Net amount recognized.................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
===========================================================================================
Company's share of net amount recognized. $ 39.3 $ (32.7) $ (117.1) $ (195.9)
===========================================================================================
Assumptions used as of December 31:
Discount rate............................ 6.75% 7.25% 6.75% 7.25%
Expected long-term return on plan assets. 9.00% 10.25% 9.00% 10.25%
Rate of compensation increase............ 3.50% 4.00% 3.50% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2002 were computed as follows:
Other
Pension Benefits Postretirement Benefits
------------------------ -------------------------
2002 2001 2000 2002 2001 2000
------------------------------------------------------------------------------------------------------
(In millions)
Service cost........................... $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3
Interest cost.......................... 249.3 133.3 104.8 113.6 64.4 45.7
Expected return on plan assets......... (346.1) (204.8) (181.0) (51.7) (9.9) (0.5)
Amortization of transition
obligation (asset) .................. -- (2.1) (7.9) 9.2 9.2 9.2
Amortization of prior service cost..... 9.3 8.8 5.7 3.2 3.2 3.2
Recognized net actuarial loss (gain)... -- -- (9.1) 11.2 4.9 --
Voluntary early retirement program..... -- 6.1 17.2 -- 2.3 --
-------------------------------------------------------------------------------------------------------
Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9
=======================================================================================================
Company's share of net benefit cost.... $ 1.6 $ (1.9) $ (5.3) $ 9.5 $12.5 $21.3
-------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately
10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. An increase in the health care cost trend
rate assumption by one percentage point would increase the total service and
interest cost components by $20.7 million and the postretirement benefit
obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
(J) 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 Service Company (FECO). 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:
2002 2001 2000
- ---------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues with FES............. $283.8 $334.1 $ --
Generating units rent with FES.... 59.8 59.1 --
Ground lease with ATSI............ 7.1 7.1 4.4
Operating Expenses:
Purchased power under PSA......... 420.4 597.4 --
Purchased power from TE........... 104.0 97.0 106.8
Transmission expenses (including
ATSI rent)..................... 41.1 28.9 15.0
FirstEnergy support services...... 52.4 49.6 97.9
Other Income:
Interest income from ATSI......... 7.2 7.2 2.4
Interest income from FES.......... 0.9 0.9 --
- ---------------------------------------------------------------------------
The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased
capacity entitlement. Purchased power expenses for this transaction were $104.0
million, $97.0 million and $104.0 million in 2002, 2001 and 2000, respectively.
This purchase is expected to continue through the end of the lease period (see
Note 2).
FirstEnergy does not bill directly or allocate any of its costs to any
subsidiary company. Costs are allocated to the Company from its affiliates, GPU
Service, Inc. and FirstEnergy Service Company, both subsidiaries of FirstEnergy
Corp. and both "mutual service companies" as defined in Rule 93 of the 1935
Public Utility Holding Company Act (PUHCA). The majority of costs are directly
billed or assigned at no more than cost as determined by PUHCA Rule 91. The
remaining costs are for services that are provided on behalf of more than one
company, or costs that cannot be precisely identified and are allocated using
formulas that are filed annually with the SEC on Form U-13-60. The current
allocation or assignment formulas used and their bases include multiple factor
formulas; the ratio of each company's amount of FirstEnergy's aggregate direct
payroll, number of employees, asset balances, revenues, number of customers and
other factors; and specific departmental charge ratios. Management believes that
these allocation methods are reasonable.
(K) 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 and $52.0 million in 2001 and 2000, respectively. There were no
capital lease transactions in 2002. "Other amortization" on the Consolidated
Statement of Cash Flows under Cash Flows from Operating Activities consists of
amounts from the reduction of an electric service obligation under the Company's
electric service prepayment program.
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:
2002 2001
- ----------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- ----------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt................................... $2,309 $2,493 $2,507 $2,624
Preferred stock.................................. $ 106 $ 113 $ 125 $ 125
Investments other than cash and cash equivalents:
Debt securities
- Maturity (5-10 years)....................... $ 11 $ 11 $ 11 $ 11
- Maturity (more than 10 years)............... 528 576 568 565
All other..................................... 232 232 214 218
- ----------------------------------------------------------------------------------------------------------
$ 771 $ 819 $ 793 $ 794
==========================================================================================================
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities with similar characteristics offered by a 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. The
Company has no securities held for trading purposes.
The investment policy for the nuclear decommissioning trust funds
restricts or limits the ability to hold certain types of assets including
private or direct placements, warrants, securities of FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "All other" in the
table above) consist of equity securities, government bonds and corporate bonds.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in the trust investment with a corresponding change to the
decommissioning liability. In conjunction with the adoption of SFAS 143 on
January 1, 2003, unrealized gains or losses were reclassified to other
comprehensive income in accordance with SFAS 115. Realized gains (losses) are
recognized as additions (reductions) to trust asset balances. For the year 2002,
net realized losses were approximately $6.9 million and interest and dividend
income totaled approximately $7.3 million.
(L) 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:
2002 2001
- ------------------------------------------------------------------------
(In millions)
Regulatory transition charge.................... $899.0 $830.3
Customer receivables for future income taxes.... 8.0 9.2
Loss on reacquired debt......................... 15.7 16.5
Other........................................... 17.1 18.5
- ------------------------------------------------------------------------
Total...................................... $939.8 $874.5
========================================================================
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 any renewal term 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, 2002 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, 2002 are
summarized as follows:
2002 2001 2000
- ------------------------------------------------------------------
(In millions)
Operating leases
Interest element...... $33.6 $35.3 $ 36.8
Other................. 42.8 36.4 29.8
Capital leases
Interest element...... 0.6 3.6 5.9
Other................. 0.4 19.4 37.4
- ------------------------------------------------------------------
Total rentals......... $77.4 $94.7 $109.9
==================================================================
The future minimum lease payments as of December 31, 2002 are:
Operating Leases
-------------------------------------
Capital Lease Capital
Leases Payments Trust Net
----------------------------------------------------------------------------------------------
(In millions)
2003.................................. $1.0 $ 77.5 $ 79.3 $ (1.8)
2004.................................. 1.0 55.7 28.6 27.1
2005.................................. 1.0 66.7 48.3 18.4
2006.................................. 1.0 71.3 56.2 15.1
2007.................................. 1.0 57.8 48.2 9.6
Years thereafter...................... 4.7 524.7 393.3 131.4
----------------------------------------------------------------------------------------------
Total minimum lease payments.......... 9.7 $853.7 $653.9 $199.8
====== ====== ======
Interest portion...................... 3.3
------------------------------------------------
Present value of net minimum
lease payments...................... 6.4
Less current portion.................. 0.4
------------------------------------------------
Noncurrent portion.................... $6.0
================================================
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.
(B) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock
Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for
Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted
stock under both Plans have been converted into FirstEnergy options and
restricted stock. Options under the GPU Plan became fully vested on November 7,
2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options
and restricted stock maintained their original vesting periods, which range from
one to four years, and will expire on or before December 17, 2006.
Additional stock-based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the 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 22.5
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.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
- ------------------------------------------------------------------------
Restricted common shares granted..... 36,922 133,162 208,400
Weighted average market price ....... $36.04 $35.68 $26.63
Weighted average vesting period
(years) ............................ 3.2 3.7 3.8
Dividends restricted................. Yes * Yes
-----------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), 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 typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
Stock option activities under the FE Programs for the past three years
were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
- ------------------------------------------------------------------------------
Balance, January 1, 2000.............. 2,153,369 $25.32
(159,755 options exercisable)......... 24.87
Options granted..................... 3,011,584 23.24
Options exercised................... 90,491 26.00
Options forfeited................... 52,600 22.20
Balance, December 31, 2000............ 5,021,862 24.09
(473,314 options exercisable)......... 24.11
Options granted..................... 4,240,273 28.11
Options exercised................... 694,403 24.24
Options forfeited................... 120,044 28.07
Balance, December 31, 2001............ 8,447,688 26.04
(1,828,341 options exercisable)....... 24.83
Options granted..................... 3,399,579 34.48
Options exercised................... 1,018,852 23.56
Options forfeited................... 392,929 28.19
Balance, December 31, 2002............ 10,435,486 28.95
(1,400,206 options exercisable)....... 26.07
As of December 31, 2002, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans, since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair-value accounting to FirstEnergy's stock
options is summarized in Note 1G - "Stock-Based Compensation."
(C) PREFERRED AND PREFERENCE STOCK-
The Company's preferred stock may be redeemed 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 2002.
The Company has three million authorized and unissued shares of
preference stock having no par value.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
The Company's $7.35 C series has an annual sinking fund requirement
for 10,000 shares with annual sinking fund requirements for the next five years
of $1.0 million in each year 2003-2007.
(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 Company has a first mortgage indenture under which it issues from
time to time first mortgage bonds secured by a direct first mortgage lien on
substantially all of its property and franchises, other than specifically
excepted property. The Company has various debt covenants under its financing
arrangements. The most restrictive of the debt covenants relate to the
nonpayment of interest and/or principal on debt which could trigger a default
and the maintenance of minimum fixed charge ratios and debt to capitalization
ratios covenants. There also exists cross-default provisions among financing
agreements of FirstEnergy and 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)
---------------------------------------------
2003................................ $386.8
2004................................ 331.0
2005................................ 300.0
2006................................ --
2007................................ 120.0
---------------------------------------------
Included in the table above are amounts for various variable interest
rate long-term debt which have provisions by which individual debt holders have
the option to "put back" or require the respective debt issuer to redeem their
debt at those times when the interest rate may change prior to its maturity
date. These amounts are $242 million and $51 million in 2003 and 2004,
respectively, which represents the next time debt holders may exercise this
provision.
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 $142.6 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
or policies, 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 unsecured letters of credit of approximately
$215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2
that expire in April 2005. The Company and TE are jointly and severally liable
for the letters of credit (see Note 2).
(G) COMPREHENSIVE INCOME-
Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common stockholder's
equity except those resulting from transactions with FirstEnergy. As of December
31, 2002, accumulated other comprehensive loss consisted of a minimum liability
for unfunded retirement benefits of $44.1 million.
4. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As
of December 31, 2002, the Company had total short-term borrowings of $288.6
million from its affiliates. The weighted average interest rates on short-term
borrowings outstanding as of December 31, 2002 and 2001, were 1.8% and 3.5%,
respectively.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$312 million for property additions and improvements from 2003-2007, of which
approximately $96 million is applicable to 2003. Investments for additional
nuclear fuel during the 2003-2007 period are estimated to be approximately $53
million, of which approximately $15 million applies to 2003. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $59 million and $28 million, respectively, as the nuclear fuel is
consumed.
(B) 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 $21.4 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.
(C) 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 $31,500 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 believes it 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 SIP
that requires compliance with the NOx budgets at the Company's Ohio facilities
by May 31, 2004.
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; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, the Company's proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. The
Company has total accrued liabilities aggregating approximately $2.8 million as
of December 31, 2002.
The effects of compliance on the Company with regard to environmental
matters could have a material adverse effect on the Company's earnings and
competitive position. These environmental regulations affect the Company's
earnings and competitive position to the extent it competes with companies that
are not subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations. The
Company believes it is in material compliance with existing regulations but is
unable to predict whether environmental regulations will change and what, if
any, the effects of such change would be.
(D) 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:
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale
had included the 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants
owned by the Company. On August 8, 2002, FirstEnergy notified NRG that it was
canceling the agreement because NRG stated that it could not complete the
transaction under the original terms of the agreement. FirstEnergy also notified
NRG that FirstEnergy reserves the right to pursue legal action against NRG, its
affiliate and its parent, Xcel Energy, for damages, based on the anticipatory
breach of the agreement. On February 25, 2003, the U.S. Bankruptcy Court in
Minnesota approved FirstEnergy's request for arbitration against NRG.
In December 2002, FirstEnergy decided to retain ownership of these
plants after reviewing other bids it subsequently received from other parties
who had expressed interest in purchasing the plants. Since FirstEnergy did not
execute a sales agreement by year-end, the Company reflected approximately $45
million ($26 million net of tax) of previously unrecognized depreciation and
other transaction costs in the fourth quarter of 2002 related to these plants
from November 2001 through December 2002 on its Consolidated Statement of
Income.
7. OTHER INFORMATION:
The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001 and 2000:
(A) Consolidated Statements of Cash Flows
2002 2001 2000
---- ---- ----
(In Thousands)
Cash Flows from Operating Activities:
Accrued taxes............................... $ (3,568) $ (48,877) $ 1,701
Accrued interest............................ (5,334) 959 (4,598)
Prepayments and other....................... 27,418 27,743 (2,930)
All other................................... (33,045) (89,114) (38,361)
--------- --------- --------
Other cash used for operating activities.. $ (14,529) $(109,289) $(44,188)
========= ========= ========
(B) Consolidated Statements of Taxes
2002 2001 2000
---- ---- ----
(In Thousands)
Other Accumulated Deferred Income Taxes
at December 31:
Retirement Benefits......................... $ (42,079) $ (73,483) $(62,594)
All other................................... (25,743) (51,927) 41,379
--------- --------- --------
Total-Other............................... $ (67,822) $(125,410) $(21,215)
========= ========= ========
8. RECENTLY ISSUED ACCOUNTING STANDARDS:
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107
and rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers
of guarantees must record the fair value of those guarantees at their inception.
This accounting guidance is applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The Company does not believe that
implementation of FIN 45 will be material but the Company will continue to
evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation of
ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions beginning in the first
interim or annual reporting period after June 15, 2003 (our third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
The Company currently has transactions with entities which may fall
within the scope of this interpretation and which are reasonably possible of
meeting the definition of a VIE in accordance with FIN 46. The Company currently
consolidates the majority of these entities and believe the Company will
continue to consolidate following the adoption of FIN 46. One of these entities
the Company is currently consolidating is the Shippingport Capital Trust which
reacquired a portion of the off-balance sheet debt issued in connection with the
sale and leaseback of our interest in the Bruce Mansfield Plant. Ownership of
the trust includes a 4.85 percent interest by nonaffiliated parties and 0.34
percent equity interest by Toledo Edison Capital Corp., an affiliated company.
9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
- -------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $425.0 $462.9 $538.9 $408.6
Operating Expenses and Taxes................ 369.7 350.1 410.4 380.0
- -------------------------------------------------------------------------------------------------------------
Operating Income............................ 55.3 112.8 128.5 28.6
Other Income................................ 5.2 3.4 5.6 1.8
Net Interest Charges........................ 47.8 46.8 47.3 43.3
- -------------------------------------------------------------------------------------------------------------
Net Income (Loss)........................... $ 12.7 $ 69.4 $ 86.8 $(12.9)
=============================================================================================================
Earnings (Loss) Applicable to Common Stock.. $ 4.4 $ 66.3 $ 83.6 $(15.7)
=============================================================================================================
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
=============================================================================================================
Report of Independent Accountants
To the Stockholders and Board of Directors of The Cleveland Electric
Illuminating Company:
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of The Cleveland
Electric Illuminating Company (a wholly owned subsidiary of FirstEnergy Corp.)
and subsidiaries as of December 31, 2002, and the results of their operations
and their cash flows for the year then ended in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
auditing standards generally accepted in the United States of America, which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion. The consolidated financial statements of The
Cleveland Electric Illuminating Company and subsidiaries as of December 31, 2001
and for each of the two years in the period ended December 31, 2001 were audited
by other independent accountants who have ceased operations. Those independent
accountants expressed an unqualified opinion on those financials statements,
before the revisions described in Note 1 to the 2002 consolidated financial
statements, in their report dated March 18, 2002.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for goodwill in 2002.
As discussed above, the consolidated financial statements of The Cleveland
Electric Illuminating Company and subsidiaries as of December 31, 2001 and for
each of the two years in the period ended December 31, 2001 were audited by
other independent accountants who have ceased operations. As described in Note 1
to the consolidated financial statements, revisions have been made to include
the transitional disclosures required by Statement of Financial Accounting
Standards No. 142, Goodwill and Other Intangible Assets, which was adopted by
the Company as of January 1, 2002. In our opinion the transitional disclosures
for 2001 and 2000 are appropriate. However, we were not engaged to audit,
review, or apply any procedures to the 2001 and 2000 consolidated financial
statements of the Company other than with respect to such disclosures and,
accordingly, we do not express an opinion or any other form of assurance on the
2001 and 2000 consolidated financial statements taken as a whole.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003
The following report is a copy of a report previously issued by Arthur Andersen
LLP and has not been reissued by Arthur Andersen LLP.
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.