EXHIBIT 13.2
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............................... 2-15
Consolidated Statements of Income.................................. 16
Consolidated Balance Sheets........................................ 17
Consolidated Statements of Capitalization.......................... 18-19
Consolidated Statements of Common Stockholder's Equity............. 20
Consolidated Statements of Preferred Stock......................... 20
Consolidated Statements of Cash Flows.............................. 21
Consolidated Statements of Taxes................................... 22
Notes to Consolidated Financial Statements......................... 23-40
Report of Independent Auditors..................................... 41
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
SELECTED FINANCIAL DATA (RESTATED*)
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
GENERAL FINANCIAL INFORMATION:
Operating Revenues ..................... $1,843,671 $2,064,622 $1,890,339 $1,864,954 $1,795,997
========== ========== ========== ========== ==========
Operating Income ....................... $ 306,152 $ 354,422 $ 397,568 $ 405,640 $ 393,397
========== ========== ========== ========== ==========
Net Income ............................. $ 136,952 $ 177,905 $ 210,424 $ 204,963 $ 175,765
========== ========== ========== ========== ==========
Earnings on Common Stock ............... $ 121,262 $ 153,067 $ 189,581 $ 171,439 $ 150,971
========== ========== ========== ========== ==========
Total Assets ........................... $6,510,243 $6,526,596 $6,756,921 $6,189,261 $6,307,683
========== ========== ========== ========== ==========
CAPITALIZATION AT DECEMBER 31:
Common Stockholder's Equity ............ $1,200,234 $1,073,041 $1,095,874 $ 990,177 $1,020,925
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 ................... $3,376,660 $3,477,126 $3,994,996 $4,027,543 $4,297,162
========== ========== ========== ========== ==========
CAPITALIZATION RATIOS:
Common Stockholder's Equity ............ 35.5% 30.9% 27.4% 24.6% 23.8%
Preferred Stock-
Not Subject to Mandatory Redemption . 2.9 4.1 6.0 5.9 5.5
Subject to Mandatory Redemption ..... 3.1 3.0 0.6 2.9 3.5
Long-Term Debt ......................... 58.5 62.0 66.0 66.6 67.2
---------- ---------- ---------- ---------- ----------
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
* See Note 1(M) to the Consolidated Financial Statements.
1
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate", "potential," "expect", "believe", "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), availability
and cost of capital, inability of the Davis-Besse Nuclear Power Station to
restart (including because of an inability to obtain a favorable final
determination from the Nuclear Regulatory Commission) in the fall of 2003,
inability to accomplish or realize anticipated benefits from strategic goals,
further investigation into the causes of the August 14, 2003, power outage, and
other similar factors.
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
========== ====== ======
(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.
2
RESTATEMENTS
As further discussed in Note 1(M) to the Consolidated Financial
Statements, the Company is restating its consolidated financial statements for
the three years ended December 31, 2002. The revisions principally reflect a
change in the method of amortizing costs being recovered through the Ohio
transition plan and recognition of above-market values of certain leased
generation facilities.
Transition Cost Amortization
As discussed under Regulatory Plan in Note 1(C) to the Consolidated
Financial Statements, CEI recovers transition costs, including regulatory
assets, through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2009.
The Company amortizes transition costs using the effective interest
method. The amortization schedules originally developed at the beginning of the
transition plan in 2001 in applying this method were based on total transition
revenues, including revenues designed to recover costs which have not yet been
incurred or that were recognized on the regulatory financial statements (fair
value purchase accounting adjustments), but not in the financial statements
prepared under generally accepted accounting principles (GAAP). The Company has
revised the amortization schedules under the effective interest method to
consider only revenues relating to transition regulatory assets recognized on
the GAAP balance sheet. The impact of this change will result in higher
amortization of these regulatory assets the first several years of the
transition cost recovery period, compared with the method previously applied.
The change in method results in no change in total amortization of previously
recorded regulatory assets recovered under the transition period through the end
of 2009.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE
and Centerior Energy Corporation (Centerior). The merger was accounted for as an
acquisition of Centerior, the parent company of CEI, under the purchase
accounting rules of Accounting Principles Board (APB) Opinion No. 16. In
connection with the reassessment of the accounting for the transition plan, the
Company reassessed its accounting for the Centerior purchase and determined that
above-market lease liabilities should have been recorded at the time of the
merger. Accordingly, the Company has restated its financial statistics to record
additional adjustments associated with the 1997 merger between OE and Centerior
to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and
the Bruce Mansfield Plant, for which CEI had previously entered into
sale-leaseback arrangements. The Company recorded an increase in goodwill
related to the above-market lease costs for Beaver Valley Unit 2 since
regulatory accounting for nuclear generating assets had been discontinued prior
to the merger date and it was determined that this additional consideration
would have increased goodwill at the date of the merger. The corresponding
impact of the above-market lease liability for the Bruce Mansfield Plant was
recorded as a regulatory asset because regulatory accounting had not been
discontinued at that time for the fossil generating assets and recovery of these
liabilities was provided under the transition plan.
The total above-market lease obligation of $611 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017 (approximately $31.2 million annually). The additional goodwill has been
recorded effective as of the merger date, and amortization has been recorded
through 2001, when goodwill amortization ceased with the adoption of Statement
of Financial Accounting Standards (SFAS) No. 142 (SFAS 142), "Goodwill and Other
Intangible Assets." The total above-market lease obligation of $457 million
associated with the Bruce Mansfield Plant is being reversed through the end of
2016 (approximately $29.0 million annually). Before the start of the transition
plan in fiscal 2001, the regulatory asset would have been amortized at the same
rate as the lease obligation resulting in no impact to net income. Beginning in
2001, the unamortized regulatory asset has been included in the Company's
revised amortization schedule for regulatory assets and amortized through the
end of the recovery period in 2009.
The Company has reflected the impact of the accounting for the
period from the merger in 1997 through 1999 as a cumulative effect adjustment of
$23.6 million to retained earnings as of January 1, 2000. The after-tax effects
of these items in the three years ended December 31, 2002, were as follows:
3
INCOME STATEMENT EFFECTS
- ------------------------
INCREASE (DECREASE) TRANSITION REVERSAL
COST OF LEASE
AMORTIZATION OBLIGATIONS(1) TOTAL
------------ -------------- ---------
(IN THOUSANDS)
Year ended December 31, 2002
Nuclear operating expenses ................ $ -- $ (31,200) $ (31,200)
Other operating expenses .................. -- (29,000) (29,000)
Provision for depreciation and amortization 52,000 51,300 103,300
Income taxes .............................. (21,945) 3,744 (18,201)
------------ -------------- ---------
Total expense ............................. $ 30,055 $ (5,156) $ 24,899
============ ============== =========
Net income effect ......................... $ (30,055) $ 5,156 $ (24,899)
============ ============== =========
Year ended December 31, 2001
Nuclear operating expenses ................ $ -- $ (31,200) $ (31,200)
Other operating expenses .................. -- (29,000) (29,000)
Provision for depreciation and amortization 53,600 56,100 109,700
Income taxes .............................. (18,714) 1,412 (17,302)
------------ -------------- ---------
Total expense ............................. $ 34,886 $ (2,688) $ 32,198
============ ============== =========
Net income effect ......................... $ (34,886) $ 2,688 $ (32,198)
============ ============== =========
Year ended December 31, 2000
Nuclear operating expenses ................ $ -- $ (31,200) $ (31,200)
Other operating expenses .................. -- -- --
Provision for depreciation and amortization -- 9,000 9,000
Income taxes .............................. -- 12,974 12,974
------------ -------------- ---------
Total expense ............................. $ -- $ (9,226) $ (9,226)
============ ============== =========
Net income effect ......................... $ -- $ 9,226 $ 9,226
============ ============== =========
(1) The provision for depreciation and amortization in each of 2001 and 2000
includes goodwill amortization of $9.0 million.
In addition, the impact increased the following balances in the
Consolidated Balance Sheet as of January 1, 2000:
(IN THOUSANDS)
Goodwill $ 340,990
Regulatory assets 457,000
---------
Total assets $ 797,990
=========
Other current liabilities $ 60,000
Deferred income taxes (225,971)
Other deferred credits 940,400
---------
Total liabilities $ 774,429
=========
Retained earnings $23,561
=======
The impact of the adjustments described above for the next five
years is expected to reduce net income in 2003 through 2005 and increase net
income in 2006 through 2007 as shown below.
CHANGE IN REGULATORY LEASE EFFECT ON EFFECT
TRANSITION COST ASSET LIABILITY PRE-TAX ON NET
YEAR AMORTIZATION AMORTIZATION (A) REVERSAL INCOME INCOME
---- ------------ ---------------- -------- ------ ------
(IN MILLIONS)
2003 $(39.4) $(57.7) $60.2 $(36.9) $(21.8)
2004 (22.9) (64.8) 60.2 (27.5) (16.2)
2005 18.3 (74.4) 60.2 4.1 2.4
2006 (9.5) (43.7) 60.2 7.0 4.1
2007 30.4 (49.5) 60.2 41.1 24.2
(a) This represents the additional amortization related to the regulatory
assets recognized in connection with the above-market lease for the Bruce
Mansfield Plant discussed above.
After giving effect to the restatement, total transition cost
amortization (including above market leases) is expected to approximate the
following for the years from 2003 through 2009 (in millions).
2003.............. $71
2004.............. 102
2005.............. 161
2006.............. 74
2007.............. 125
2008.............. 213
2009.............. 55
4
Other Unrecorded Adjustments
This restatement for the three years ended December 31, 2002 also
includes adjustments that were not previously recognized that principally
related to an adjustment to unbilled revenues in 2001 with corresponding impact
in 2002. The net income impact by year was $7.6 million in 2002, $(7.9) million
in 2001 and $(1.8) million in 2000.
The effects of all the changes on the Consolidated Statements of
Income previously reported for the three years ended December 31, 2002 are as
follows:
2002 2001 2000
-------------------------- -------------------------- --------------------------
AS PREVIOUSLY RESTATED AS PREVIOUSLY RESTATED AS PREVIOUSLY RESTATED
PRESENTED PRESENTATION PRESENTED PRESENTATION PRESENTED PRESENTATION
---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
Revenues ......................... $1,835,371 $1,843,671 $2,076,222 $2,064,622 $1,887,039 $1,890,339
Expenses ......................... 1,510,225 1,537,519 1,680,661 1,710,200 1,496,945 1,492,771
Other income ..................... 15,971 15,971 13,292 13,292 12,568 12,568
---------- ---------- ---------- ---------- ---------- ----------
Income before net interest charges 341,117 321,123 408,853 367,714 402,662 410,136
Net interest charges ............. 185,171 185,171 189,809 189,809 199,712 199,712
---------- ---------- ---------- ---------- ---------- ----------
Net income ....................... 155,946 136,952 219,044 177,905 202,950 210,424
Preferred stock dividend
requirements ..................... 17,390 15,690 25,838 24,838 20,843 20,843
---------- ---------- ---------- ---------- ---------- ----------
Earnings on common stock ......... $ 138,556 $ 121,262 $ 193,206 $ 153,067 $ 182,107 $ 189,581
========== ========== ========== ========== ========== ==========
RESULTS OF OPERATIONS
Earnings on common stock in 2002 decreased 20.8% to $121.3 million
in 2002 from $153.1 million in 2001 and $189.6 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 of corporate restructuring
shown in the table above, earnings on common stock decreased by 19.3% in 2001
from 2000.
Operating revenues decreased $221.0 million or 10.7% 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 Corporate Restructuring table
above, operating revenues decreased by $221.9 million or 11.7% 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.
5
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 $172.7 million in
2002 and increased by $217.4 million in 2001 from 2000. Excluding the effects of
restructuring, total 2001 operating expenses and taxes were $173.3 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
- -------------------------------------- ------- -------
RESTATED
(SEE NOTE 1(M))
INCREASE (DECREASE) (IN MILLIONS)
Fuel and purchased power ........................... $(181.2) $ (145.6)
Nuclear operating costs ............................ 98.7 (11.8)
Other operating costs .............................. 16.5 (41.6)
------- -------
TOTAL OPERATION AND MAINTENANCE EXPENSES ......... (66.0) (199.0)
Provision for depreciation and amortization ........ (59.7) 80.4
General taxes ...................................... 2.9 (64.8)
Income taxes ....................................... (49.9) 10.1
------- -------
TOTAL OPERATING EXPENSES AND TAXES ............... $(172.7) $ (173.3)
------- -------
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 $16.5 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
$11.4 million in 2001 from the prior year due to one less nuclear refueling
outage in 2001. Other operating costs decreased $41.6 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 $59.7 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
increased by $80.4 million due to amortization of transition costs offset by 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.
6
Preferred Stock Dividend Requirements
Preferred stock dividend requirements were $9.1 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.
7
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
====== ====== ====== ====== =======
(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.
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
8
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. 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)
9
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 $1,191.8 million and $1,230.2 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 fall 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).
10
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
------
Power Outage
On August 14, 2003, eight states and southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. The cause of the outage has not been
determined. After having restored service to its customers, FirstEnergy is
accumulating data and evaluating the status of its electrical system prior to
and during the outage event. FirstEnergy is committed to working with the North
American Electric Reliability Council and others involved to determine exactly
what events in the entire affected region led to the outage. There is no
timetable as to when this entire process will be completed. It is, however,
expected to last several weeks, at a minimum
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.
11
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, the CEI's regulatory assets totaled $1,191.8 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:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy system
- Mix of KWH usage by residential, commercial and industrial customers
- 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
12
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.
Ohio Transition Cost Amortization
In developing CEI's restructuring plan, the PUCO determined
allowable transition costs based on amounts recorded on the EUOC's regulatory
books. These costs exceeded those deferred or capitalized on CEI's balance sheet
prepared under GAAP since they included certain costs which have not yet been
incurred or that were recognized on the regulatory financial statements (fair
value purchase accounting adjustments). The Company uses an effective interest
method for amortizing its transition costs, often referred to as a
"mortgage-style" amortization. The interest rate under this method is equal to
the rate of return authorized by the PUCO in the transition plan for CEI. In
computing the transition cost amortization, CEI includes only the portion of the
transition revenues associated with transition costs included on the balance
sheet prepared under GAAP. Revenues collected for the off balance sheet costs
and the return associated with these costs are recognized as income when
received.
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).
13
Goodwill
The Regulators in the jurisdictions that CEI operates does not
provide for recovery of goodwill. As a result, no amortization of goodwill has
been recorded subsequent to the adoption of SFAS 142. 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 $1.7 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 $242.1 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).
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.
14
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 in the first interim or
annual reporting period beginning after June 15, 2003 (CEI's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
CEI currently has transactions 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. CEI currently consolidates the majority of
these entities and believes it will continue to consolidate following the
adoption of FIN 46. One of these entities CEI 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 its interest in the
Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest
by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison
Capital Corp., a majority owned subsidiary.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 is effective for financial
instruments entered into or modified after May 31, 2003 and is effective at the
beginning of the first interim period beginning after June 15, 2003 (CEI's third
quarter of 2003) for all other financial instruments.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003 which would correspond to
FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue
C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify
for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides
guidance regarding when the presence in a contract of a general index, such as
the Consumer Price Index, would prevent that contract from qualifying for the
normal purchases and normal sales (NPNS) exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts. DIG
Issue C20 is to be applied prospectively to all existing contracts as of its
effective date and for all future transactions. If it is determined under DIG
Issue C20 guidance that the NPNS exception was claimed for an existing contract
that was not eligible for this exception, the contract will be recorded at fair
value, with a corresponding adjustment of net income as the cumulative effect of
a change in accounting principle in the fourth quarter of 2003. CEI is currently
assessing the new guidance and has not yet determined the impact on its
financial statements.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when arrangements
contain a lease. Based on the EITF consensus, an arrangement contains a lease if
(1) it identifies specific property, plant or equipment (explicitly or
implicitly), and (2) the arrangement transfers the right to the purchaser to
control the use of the property, plant or equipment. The consensus will be
applied prospectively to arrangements committed to, modified or acquired through
a business combination, beginning in the third quarter of 2003. CEI is currently
assessing the new EITF consensus and has not yet determined the impact on its
financial position or results of operations following adoption.
15
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
OPERATING REVENUES (NOTE 1)................................. $1,843,671 $2,064,622 $1,890,339
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1)........................ 587,108 768,306 414,127
Nuclear operating costs (Note 1)......................... 207,313 108,587 120,371
Other operating costs (Note 1)........................... 279,242 262,745 381,118
----------- ----------- -----------
Total operation and maintenance expenses............... 1,073,663 1,139,638 915,616
Provision for depreciation and amortization.............. 244,727 304,417 229,915
General taxes............................................ 147,804 144,948 222,297
Income taxes............................................. 71,325 121,197 124,943
------------ ----------- -----------
Total operating expenses and taxes..................... 1,537,519 1,710,200 1,492,771
---------- ---------- ----------
OPERATING INCOME............................................ 306,152 354,422 397,568
OTHER INCOME (NOTE 1)....................................... 15,971 13,292 12,568
------------ ------------ ------------
INCOME BEFORE NET INTEREST CHARGES.......................... 322,123 367,714 410,136
----------- ----------- -----------
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.................................................. 136,952 177,905 210,424
PREFERRED STOCK DIVIDEND
REQUIREMENTS............................................. 15,690 24,838 20,843
------------ ------------ -------------
EARNINGS ON COMMON STOCK.................................... $ 121,262 $ 153,067 $ 189,581
=========== =========== ===========
* See Note 1(M)
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
16
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS (RESTATED*)
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 9,406
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
---------- ----------
311,127 265,343
---------- ----------
DEFERRED CHARGES:
Regulatory assets ........................................................... 1,191,804 1,230,288
Goodwill .................................................................... 1,693,629 1,693,629
Property taxes .............................................................. 79,430 80,470
Other ....................................................................... 24,798 8,297
---------- ----------
2,989,661 3,012,684
---------- ----------
$6,510,243 $6,526,596
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity ................................................. $1,200,001 $1,082,041
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
---------- ----------
3,376,427 3,486,126
---------- ----------
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 .............................................................. 126,261 124,677
Accrued interest ............................................................ 51,767 57,101
Other ....................................................................... 124,624 124,264
---------- ----------
1,261,672 1,042,171
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes ........................................... 407,297 413,638
Accumulated deferred investment tax credits ................................. 70,803 75,435
Nuclear plant decommissioning costs ......................................... 242,511 206,698
Pensions and other postretirement benefits .................................. 171,968 231,365
Deferred lease costs ........................................................ 788,800 849,000
Other ....................................................................... 190,765 222,163
---------- ----------
1,872,144 1,998,299
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)
---------- ----------
$6,510,243 $6,526,299
========== ==========
* See Note 1(M)
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
17
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*)
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)..................................... (44,284) 9,000
Retained earnings (Note 3A)........................................................ 262,323 141,079
---------- ----------
Total common stockholder's equity................................................ 1,200,001 1,082,041
---------- ----------
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
---------- ----------
* See Note 1(M)
18
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*)(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 ................ $ 3,376,427 $ 3,486,126
=========== ===========
* See Note 1(M).
**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.
19
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (RESTATED)
ACCUMULATED
OTHER
COMPREHENSIVE NUMBER CARRYING COMPREHENSIVE RETAINED
INCOME OF SHARES VALUE INCOME (LOSS) EARNINGS
------ --------- ----- ------------- --------
RESTATED RESTATED
(SEE NOTE 1(M)) (SEE NOTE 1(M))
(DOLLARS IN THOUSANDS)
Balance, January 1, 2000....................... 79,590,689 $931,962 $ -- $ 34,654
Cumulative effect for restatements
(see Note 1(M))........................... 23,561
- --------------------------------------------------------------------------------------------------------------------------------
Restated Balance at January 1, 2000............ 58,215
Net income.................................. $ 210,424 210,424
=========
Cash dividends on preferred stock........... (20,727)
Cash dividends on common stock.............. (84,000)
- --------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000..................... 79,590,689 931,962 -- 163,912
Net income.................................. $ 177,905 177,905
---------
Unrealized gain on instruments, net of
$5,900 of income taxes.................... 9,000
---------
Comprehensive income........................ $ 186,905
=========
Cash dividends on preferred stock........... (24,838)
Cash dividends on common stock.............. (175,900)
- --------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001..................... 79,590,689 931,962 9,000 141,079
Net income.................................. $ 136,952 136,952
Unrealized loss on investments, net of
$(6,058) of income taxes.................. (9,233) (9,233)
Minimum liability for unfunded retirement
benefits, net of $(31,359,000) of income
taxes.................................... (44,051) (44,051)
---------
Comprehensive income........................ $ 83,668
=========
Equity contribution from parent............. 50,000
Cash dividends on preferred stock........... (10,965)
Preferred stock redemption premiums......... (4,743)
- --------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002..................... 79,590,689 $981,962 $(44,284) $ 262,323
===============================================================================================================================
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
========================================================================================
* See Note 1(M).
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
20
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income .................................................. $ 136,952 $ 177,905 $ 210,424
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization ............ 244,727 304,417 229,915
Nuclear fuel and lease amortization .................... 21,044 30,539 37,217
Other amortization ..................................... (15,008) (14,071) (11,635)
Deferred income taxes, net ............................. 3,637 32,741 32,726
Investment tax credits, net ............................ (4,632) (3,770) (3,617)
Receivables ............................................ (27,159) 42,542 (20,175)
Materials and supplies ................................. (7,624) 15,949 (1,697)
Accounts payable ....................................... 47,147 (52,068) 20,817
Deferred lease costs ................................... (60,200) (60,200) (31,200)
Accrued taxes .......................................... (3,568) (48,877) 3,074
Accrued interest ....................................... (5,334) 959 (4,598)
Prepayments and other .................................. 27,418 27,743 (2,930)
Other .................................................. (40,245) (88,314) (32,061)
--------- --------- ---------
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 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 ....................................................... (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
========= ========= =========
* See Note 1(M).
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
21
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES (RESTATED*)
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 ............................................. $ 76,364 $ 92,739 $ 108,024
State ............................................... 14,721 16,177 1,294
--------- --------- ---------
91,085 108,916 109,318
--------- --------- ---------
Deferred, net-
Federal ............................................. (3,661) 32,368 31,097
State ............................................... 2,146 1,125 1,629
--------- --------- ---------
(1,515) 33,493 32,726
--------- --------- ---------
Investment tax credit amortization ..................... (4,632) (4,522) (3,617)
--------- --------- ---------
Total provision for income taxes ................ $ 84,938 $ 137,887 $ 138,427
========= ========= =========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income ....................................... $ 71,325 $ 121,197 $ 124,943
Other income ........................................... 13,613 16,690 13,484
--------- --------- ---------
Total provision for income taxes ................ $ 84,938 $ 137,887 $ 138,427
========= ========= =========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes .......... $ 221,890 $ 315,792 $ 348,851
========= ========= =========
Federal income tax expense at statutory rate ........... $ 77,662 $ 110,527 $ 122,098
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit 10,964 11,246 1,900
Amortization of investment tax credits .............. (4,632) (4,522) (3,617)
Amortization of tax regulatory assets ............... 999 1,012 693
Amortization of goodwill ............................ -- 16,530 16,509
Other, net .......................................... (55) 3,094 844
--------- --------- ---------
Total provision for income taxes ................ $ 84,938 $ 137,887 $ 138,427
========= ========= =========
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences ............................. $ 473,506 $ 463,344 $ 495,588
Competitive transition charge .......................... 371,486 424,484 320,618
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 ............................. (31,517) 5,900 --
Above market leases .................................... (350,299) (375,333) (400,367)
Retirement Benefits .................................... (42,079) (73,483) (62,594)
All other .............................................. (29,154) (51,481) 38,758
--------- --------- ---------
Net deferred income tax liability ............... $ 407,297 $ 413,638 $ 376,130
========= ========= =========
* See Note 1(M).
** 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.
22
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,
23
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
(see Note 1(M)) 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. See Note 1(M) for
further discussion of the Ohio transition plan.
(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.
24
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 $242.4. 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 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 $47.2 million of goodwill
annually. The goodwill balance as of December 31, 2002 and 2001 was $1.694
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.............................. $136,952 $177,905 $210,424
Add back goodwill amortization................... -- 47,230 47,170
-------- -------- --------
Adjusted net income.............................. $136,952 $225,135 $257,594
======== ======== ========
(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 .
=================================================================================================
25
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
26
$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.
27
(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:
28
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.
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
---- ----
REVISED
-------
(SEE NOTE 1(M))
---------------
(IN MILLIONS)
Regulatory transition charge.................... $1,151.0 $1,186.1
Customer receivables for future income taxes.... 8.0 9.2
Loss on reacquired debt......................... 15.7 16.5
Other........................................... 17.1 18.5
--------------------------------------------------------------------------
Total...................................... $1,191.8 $1,230.3
==========================================================================
(M) RESTATEMENTS
The Company is restating its financial statements for the three years
ended December 31, 2002. The primary modifications include revisions to reflect
a change in the method of amortizing costs being recovered through the Ohio
transition plan and recognition of above-market values of certain leased
generation facilities. In addition, certain other immaterial previously
unrecorded adjustments are now reflected in results for the three years ended
December 31, 2002.
29
Transition Cost Amortization -
The Company amortizes transition costs, described in Note 1(C) above,
using the effective interest method. The amortization schedules originally
developed at the beginning of the transition plan in 2001 in applying this
method were based on total transition revenues, including revenues designed to
recover costs which have not yet been incurred or that were recognized on the
regulatory financial statements but not in the financial statements prepared
under GAAP. CEI has revised the amortization schedule under the effective
interest method to consider only revenues relating to transition regulatory
assets recognized on the GAAP balance sheet. The impact of this change will
result in higher amortization of these regulatory assets the first several years
of the transition cost recovery period, compared with the method previously
applied. The change in method results in no change in total amortization of the
regulatory assets previously recoded recovered under the transition period
through the end of 2009.
Above-Market Lease Costs -
In 1997, FirstEnergy Corp. was formed through a merger between OE and
Centerior. The merger was accounted for as an acquisition of Centerior, the
parent company of CEI, under the purchase accounting rules of APB 16. In
connection with the reassessment of the accounting for the transition plan, the
Company reassessed its accounting for the Centerior purchase and determined that
above-market lease liabilities should have been recorded at the time of the
merger. Accordingly, the Company has restated its financial status to record
additional adjustments associated with the 1997 merger between OE and Centerior
to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and
the Bruce Mansfield Plant, for which CEI had previously entered into
sale-leaseback arrangements. The Company recorded an increase in goodwill
related to the above-market lease costs for Beaver Valley Unit 2 because
regulatory accounting for nuclear generating assets had been discontinued prior
to the merger date and it was determined that this additional consideration
would have increased goodwill at the date of the merger. The corresponding
impact of the above-market lease liability for the Bruce Mansfield Plant was
recorded as a regulatory asset because regulatory accounting had not been
discontinued at that time for the fossil generating assets and recovery of these
liabilities was provided under the Company's Regulatory Plan in effect at the
time of the merger and subsequently under the transition plan.
The total above-market lease obligation of $611 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017 (approximately $31.2 million annually). The additional goodwill has been
recorded effective as of the merger date, and amortization has been recorded
through 2001, when goodwill amortization ceased with the adoption of SFAS 142.
The total above-market lease obligation of $457 million associated with the
Bruce Mansfield Plant is being amortized through the end of 2016 (approximately
$29.0 million annually). Before the start of the transition plan in 2001, the
regulatory asset would have been amortized at the same rate as the lease
obligation resulting in no impact to net income. Beginning in 2001, the
unamortized regulatory asset has been included in the Company's revised
amortization schedule for regulatory assets and amortized through the end of the
recovery period in 2009.
The Company has reflected the impact of the accounting for the period
from the merger in 1997 through 1999 as a cumulative effect adjustment of $23.6
million to retained earnings as of January 1, 2000. The after-tax effect of
these items in the three years ended December 31, 2002 was as follows:
30
INCOME STATEMENT EFFECTS
- ------------------------
INCREASE (DECREASE) TRANSITION ABOVE
COST MARKET LEASES
AMORTIZATION (1) TOTAL
------------ -------------- -----
(IN THOUSANDS)
Year ended December 31, 2002
Nuclear operating expenses $ -- $(31,200) $ (31,200)
Other operating expenses -- (29,000) (29,000)
Provision for depreciation and amortization 52,000 51,300 103,300
-------- -------- ---------
Income taxes (21,945) 3,744 (18,201)
-------- -------- ---------
Total expense $ 30,055 $ (5,156) $ 24,899
======== ======== =========
Net income effect $(30,055) $ 5,156 $ (24,899)
======== ======== =========
Year ended December 31, 2001
Nuclear operating expenses $ -- $(31,200) $ (31,200)
Other operating expenses -- (29,000) (29,000)
Provision for depreciation and amortization 53,600 56,100 109,700
-------- -------- ---------
Income taxes (18,714) 1,412 (17,302)
-------- -------- ---------
Total expense $ 34,886 $ (2,688) $ 32,198
======== ======== =========
Net income effect $(34,886) $ 2,688 $ (32,198)
======== ======== =========
Year ended December 31, 2000
Nuclear operating expenses $ -- $(31,200) $ (31,200)
Other operating expenses -- -- --
Provision for depreciation and amortization -- 9,000 9,000
-------- -------- ---------
Income taxes -- 12,974 12,974
-------- -------- ---------
Total expense $ -- $ (9,226) $ (9,226)
======== ======== =========
Net income effect $ -- $ 9,226 $ 9,226
======== ======== =========
(1) The provision for depreciation and amortization in each of 2001 and 2000
includes goodwill amortization of $9.0 million.
In addition, the impact increased the following balances in the
Consolidated Balance Sheet as of January 1, 2000:
(in thousands)
Goodwill $ 340,990
Regulatory assets 457,000
---------
Total assets $ 797,990
=========
Other current liabilities $ 60,000
Deferred income taxes (225,971)
Other deferred credits 940,400
---------
Total liabilities $ 774,429
=========
Retained earnings $ 23,561
=========
The impact of the adjustments described above for the next five
years is expected to reduce net income in 2003 through 2005 and increase net
income in 2006 through 2007.
After giving effect to the restatement, total transition cost
amortization (including above market leases) is expected to approximate the
following for the years from 2003 through 2007 (in millions).
2003.............. $ 71
2004.............. 102
2005.............. 161
2006.............. 74
2007.............. 125
2008.............. 213
2009.............. 55
31
Other Unrecorded Adjustments
This restatement for the three years ended December 31, 2002 also
includes adjustments that were not previously recognized that principally
related to an adjustment to unbilled revenue in 2001 with a corresponding impact
in 2002. The net impact by year was $7.6 million in 2002, $(7.9) million in 2001
and $(1.8) million in 2000.
The effects of all of the changes in this restatement on the
previously reported Consolidated Balance Sheet as of December 31, 2002 and 2001,
and the Consolidated Statements of Income and Consolidated Statements of Cash
Flows for the years ended December 31, 2002, 2001 and 2000 are as follows:
2002 2001 2000
-------------------------------------------------------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
-------------------------------------------------------------------------------
(IN THOUSANDS)
CONSOLIDATED STATEMENTS OF INCOME
OPERATING REVENUES $1,835,371 $1,843,671 $2,076,222 $2,064,622 $ 1,887,039 $ 1,890,339
Total revenues
EXPENSES:
Fuel and purchased power 587,108 587,108 768,306 768,306 414,127 414,127
Nuclear operating costs 238,513 207,313 139,787 108,587 151,571 120,371
Other operating expenses 307,142 279,242 290,945 262,745 374,818 381,118
Provision for depreciation and amortization 141,427 244,727 194,717 304,417 220,915 229,915
General taxes 147,804 147,804 144,948 144,948 222,297 222,297
Income taxes 88,231 71,325 141,958 121,197 113,217 124,943
---------- ---------- ---------- ---------- ----------- -----------
Total expenses 1,510,225 1,537,519 1,680,661 1,710,200 1,496,945 1,492,771
---------- ---------- ---------- ---------- ----------- -----------
OPERATING INCOME 325,146 306,152 395,561 354,422 390,094 397,568
OTHER INCOME 15,971 15,971 13,292 13,292 12,568 12,568
---------- ---------- ---------- ---------- ----------- -----------
INCOME BEFORE NET INTEREST CHARGES 341,117 322,123 408,853 367,714 402,662 410,136
NET INTEREST CHARGES 185,171 185,171 189,809 189,809 199,712 199,712
---------- ---------- ---------- ---------- ----------- -----------
NET INCOME 155,946 136,952 219,044 177,905 202,950 210,424
PREFERRED STOCK DIVIDEND REQUIREMENT 17,390 15,690 25,838 24,838 20,843 20,843
---------- ---------- ---------- ---------- ----------- -----------
EARNINGS ON COMMON STOCK $ 138,556 $ 121,262 $ 193,206 $ 153,067 $ 182,107 $ 189,581
========== ========== ========== ========== =========== ===========
CONSOLIDATED BALANCE SHEETS
ASSETS
CURRENT ASSETS $ 311,127 $ 311,127 $ 273,643 $ 265,343
PROPERTY, PLANT AND EQUIPMENT 2,419,039 2,419,039 2,433,385 2,433,385
INVESTMENTS 790,416 790,416 815,184 815,184
DEFERRED CHARGES:
Regulatory assets 939,804 1,191,804 874,488 1,230,288
Goodwill 1,370,639 1,693,629 1,370,639 1,693,629
Other (Note 2I) 104,228 104,228 88,767 88,767
---------- ---------- ---------- ----------
2,414,671 2,989,661 2,333,894 3,012,684
---------- ---------- ---------- ----------
$5,935,253 $6,510,243 $5,856,106 $6,526,596
========== ========== ========== ==========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES $1,201,373 $1,261,672 $ 983,724 $1,042,171
CAPITALIZATION
Common stockholders' equity 1,226,632 1,200,234 1,082,145 1,073,041
Preferred stock of consolidated subsidiaries --
Not subject to mandatory redemption 96,404 96,404 141,475 141,475
Subject to mandatory redemption 5,021 5,021 6,288 6,288
Subsidiary-obligated mandatorily
redeemable preferred securities (Note 5F) 100,000 100,000 100,000 100,000
Long-term debt 1,975,001 1,975,001 2,156,322 2,156,322
---------- ---------- ---------- ----------
3,403,058 3,376,660 3,486,230 3,477,126
---------- ---------- ---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 659,044 407,455 637,339 407,738
Accumulated investment tax credit 72,125 70,803 76,187 75,435
Decommissioning liability 239,720 242,120 220,798 221,598
Other 359,933 1,151,533 451,828 1,302,528
---------- ---------- ---------- ----------
1,330,822 1,871,911 1,386,152 2,007,299
---------- ---------- ---------- ----------
$5,935,253 $6,510,243 $5,856,106 $6,526,596
========== ========== ========== ==========
32
2002 2001 2000
---------------------------------------------------------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
---------------------------------------------------------------------------------
(IN THOUSANDS)
CONSOLIDATED STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 155,946 $ 136,952 $ 219,044 $ 177,905 $ 202,950 $ 210,424
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 141,427 244,727 194,717 304,417 220,915 229,915
Nuclear fuel and lease amortization 21,044 21,044 30,539 30,539 37,217 37,217
Other amortization, net (15,008) (15,008) (14,071) (14,071) (11,635) (11,635)
Deferred lease costs -- (60,200) -- (60,200) -- (31,200)
Deferred income taxes, net 19,973 3,637 46,976 32,741 22,373 32,726
Investment tax credits, net (4,062) (4,632) (3,770) (3,770) (3,617) (3,617)
Receivables (27,159) (27,159) 30,942 42,542 (16,875) (20,175)
Materials and supplies (7,624) (7,624) 15,949 15,949 (1,697) (1,697)
Accounts payable 47,147 47,147 (45,542) (52,068) 20,817 20,817
Other (14,529) (21,729) (109,289) (108,489) (44,188) (36,515)
--------- --------- --------- --------- --------- ---------
NET CASH PROVIDED FROM OPERATING ACTIVITIES $ 317,155 $ 317,155 $ 365,495 $ 365,495 $ 426,260 $ 426,260
--------- --------- --------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES $(140,076) $(140,076) $(192,384) $(192,384) $(435,638) $(435,638)
CASH FLOWS FROM INVESTING ACTIVITIES $(146,993) $(146,993) $(175,670) $(175,670) $ 11,857 $ 11,857
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
====== ====== ======
33
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
34
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
35
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.
36
(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.
37
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 AND OTHER CONTINGENCIES
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. 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
38
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.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 is effective for financial
instruments entered into or modified after May 31, 2003 and is effective at the
beginning of the first interim period beginning after June 15, 2003 (CEI's third
quarter of 2003) for all other financial instruments.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003 which would correspond to CEI's
fourth quarter of 2003. The issue supersedes earlier DIG Issue C11,
"Interpretation of Clearly and Closely Related in Contracts That Qualify for the
Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance
regarding when the presence in a contract of a general index, such as the
Consumer Price Index, would prevent that contract from qualifying for the normal
purchases and normal sales (NPNS) exception under SFAS 133, as amended, and
therefore exempt from the mark-to-market treatment of certain contracts. DIG
Issue C20 is to be applied prospectively to all existing contracts as of its
effective date and for all future transactions. If it is determined under DIG
Issue C20 guidance that the NPNS exception was claimed for an existing contract
that was not eligible for this exception, the contract will be recorded at fair
value, with a corresponding adjustment of net income as the cumulative effect of
a change in accounting principle in the fourth quarter of 2003. CEI is currently
assessing the new guidance and has not yet determined the impact on its
financial statements.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when
arrangements contain a lease. Based on the EITF consensus, an arrangement
contains a lease if (1) it identifies specific property, plant or equipment
(explicitly or implicitly), and (2) the arrangement transfers the right to the
purchaser to control the use of the property, plant or equipment. The consensus
will be applied prospectively to arrangements committed to, modified or acquired
through a business combination, beginning in the third quarter of 2003. CEI is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
39
8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002(a) JUNE 30, 2002(a) SEPTEMBER 30, 2002(a) DECEMBER 31, 2002(a)
- -------------------------------------------------------------------------------------------------------------------------------
AS AS AS AS
PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
-------- -------- -------- -------- -------- -------- -------- --------
(IN MILLIONS)
Operating Revenues $425.0 $433.3 $462.9 $462.9 $538.9 $538.9 $408.6 $408.6
Operating Expenses and Taxes 369.7 375.8 350.1 355.8 410.4 419.0 380.0 387.0
Operating Income 55.3 57.5 112.8 107.1 128.5 119.9 28.6 21.6
- -------------------------------------------------------------------------------------------------------------------------------
Other Income 5.2 5.2 3.4 3.4 5.6 5.6 1.8 1.8
Net Interest Charges 47.8 47.8 46.8 46.8 47.3 47.3 43.3 43.3
Net Income (Loss) $ 12.7 $ 14.9 $ 69.4 $ 63.7 $ 86.8 $ 78.2 $(12.9) $(19.8)
- -------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Applicable to
Common Stock $ 4.4 $ 8.3 $ 66.3 $ 60.6 $ 83.6 $ 75.1 $(15.7) $(22.8)
===============================================================================================================================
THREE MONTHS ENDED MARCH 31, 2001(a) JUNE 30, 2001(a) SEPTEMBER 30, 2001(a) DECEMBER 31, 2001(a)
- -------------------------------------------------------------------------------------------------------------------------------
AS AS AS AS
PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
-------- -------- -------- -------- -------- -------- -------- --------
(IN MILLIONS)
Operating Revenues $516.4 $513.1 $498.8 $498.8 $603.3 $603.3 $457.7 $449.4
Operating Expenses and Taxes 463.0 469.7 420.2 428.2 430.0 438.1 367.4 374.1
Operating Income 53.4 43.4 78.6 70.6 173.3 165.2 90.3 75.3
- -------------------------------------------------------------------------------------------------------------------------------
Other Income 4.4 4.4 1.1 1.1 4.0 4.0 3.7 3.7
Net Interest Charges 46.2 46.2 47.2 47.2 48.4 48.4 48.0 48.0
Net Income $ 11.6 $ 1.6 $ 32.5 $ 24.5 $128.9 $120.8 $ 46.0 $ 31.0
- -------------------------------------------------------------------------------------------------------------------------------
Earnings on common Stock $ 5.1 $ (4.9) $ 25.4 $ 17.4 $122.6 $114.5 $ 40.1 $ 26.1
===============================================================================================================================
(a) See Note 1(M) for discussion of restated financial data. The changes are
principally based on the impact of the Revised transition cost
amortization and above market leases. In addition, the other adjustments
discussed in Note 1(m) increased (decreased) net income for the quarterly
periods as follows:
<Table>
<Caption>
2002 2001
---- ----
March 31 9.2 (1.9)
December 31 (1.6) (6.0)
</Table>
40
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of The Cleveland Electric
Illuminating Company:
In our opinion, the accompanying consolidated balance sheets and consolidated
statements 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 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 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 audits 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
audits provide a reasonable basis for our opinion.
As discussed in Note 1(D) to the consolidated financial statements, the Company
changed its method of accounting for goodwill in 2002.
As discussed in Note 1(M) to the consolidated financial statements, the Company
has restated its previously issued consolidated financial statements as of
December 31, 2002 and 2001 and for each of the three years in the period ended
December 31, 2002.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
41