SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K/A
AMENDMENT NO. 2
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________________ TO _____________________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO.
----------- ------------------------------------------- ------------------
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020
(AN OHIO CORPORATION)
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- ---------------------
The Cleveland Electric Cumulative Serial Preferred Stock, without
Illuminating Company par value:
$7.40 Series A Both series registered on New
Adjustable Rate, Series L York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days: Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether each registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act): Yes [X] No [ ]
State the aggregate market value of the common stock held by
non-affiliates of the registrant: None.
Indicate the number of shares outstanding of the registrant's classes
of common stock, as of the latest practicable date:
OUTSTANDING
CLASS AS OF MARCH 24, 2003
----- --------------------
The Cleveland Electric Illuminating Company, no par value 79,590,689
EXPLANATORY NOTE
We are filing this Amendment No. 2 to our Annual Report on Form 10-K/A for the
year ended December 31, 2002 (the "Report") to correct certain typographical and
minor computational errors in Item 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION and Item 8 - FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA of the Report (filed originally as part of Exhibit 13 to
the Report). This Amendment has no effect on previously reported results of
operations or financial position.
The complete amended and restated Item 7, which is included in its entirety
below, reflects the following corrections:
Under the heading "Restatements":
Under the subheading "Above-Market Lease Costs":
In the table following the sixth paragraph, the total transition cost
amortization is corrected as follows:
(IN MILLIONS)
AS ORIGINALLY FILED AS CORRECTED
------------------- ------------
2003 $ 71 $169
2004 102 190
2005 161 217
2006 74 128
2007 125 145
2008 213 163
2009 55 43
Under the heading "Results of Operations":
Under the subheading "Operating Expenses and Taxes":
In the second sentence of the first paragraph, total 2001 operating
expenses and taxes of $173.3 million should have read $185.7 million.
In the table, the change in 2001 operating expenses and taxes is
corrected as follows:
(IN MILLIONS)
AS ORIGINALLY FILED AS CORRECTED
------------------- ------------
Income taxes 10.1 (2.3)
Total operating expenses
and taxes (173.3) (185.7)
In the second sentence of the third paragraph, the decrease in nuclear
operating costs in 2001 of $11.4 million should have read $11.8
million.
Under the heading "Capital Resources and Liquidity":
Under the subheading "Cash Flows from Operating Activities":
The Operating Cash Flow table is corrected as follows:
(IN MILLIONS)
2002 2001
AS ORIGINALLY FILED AS CORRECTED AS ORIGINALLY FILED AS CORRECTED
------------------- ------------ ------------------- ------------
Cash earnings $319.3 $326.5 $ 473.4 $ 467.6
Working capital and other (2.1) (9.3) (107.9) (102.1)
The complete amended and restated Item 8, which is included in its entirety
below, reflects the following corrections:
NOTES TO FINANCIAL STATEMENTS:
Under Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Under the subheading "(M) RESTATEMENTS":
Under the subheading "Above-Market Lease Costs":
In the table following the sixth paragraph, the total transition cost
amortization is corrected as follows:
(IN MILLIONS)
AS ORIGINALLY FILED AS CORRECTED
------------------- ------------
2003 $ 71 $169
2004 102 190
2005 161 217
2006 74 128
2007 125 145
2008 213 163
2009 55 43
EXHIBIT 12.3 CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
As a result of the restatements, the fixed charge ratios exhibit has been
revised.
FORM 10-K/A
TABLE OF CONTENTS
PAGE
----
PART I
Item 1. Business.................................................................................... *
Recent Developments....................................................................... *
Environmental Matters................................................................... *
Regulatory Matters...................................................................... *
International Operations................................................................ *
Other Matters........................................................................... *
The Company............................................................................... *
Divestitures.............................................................................. *
International Operations................................................................ *
Generating Assets....................................................................... *
Utility Regulation........................................................................ *
PUCO Rate Matters....................................................................... *
NJBPU Rate Matters...................................................................... *
PPUC Rate Matters....................................................................... *
FERC Rate Matters....................................................................... *
Regulatory Accounting................................................................... *
Capital Requirements...................................................................... *
Met-Ed Capital Trust and Penelec Capital Trust............................................ *
Nuclear Regulation........................................................................ *
Nuclear Insurance......................................................................... *
Environmental Matters..................................................................... *
Air Regulation.......................................................................... *
Water Regulation........................................................................ *
Waste Disposal.......................................................................... *
Summary................................................................................. *
Fuel Supply............................................................................... *
System Capacity and Reserves.............................................................. *
Regional Reliability...................................................................... *
Competition............................................................................... *
Research and Development.................................................................. *
Executive Officers........................................................................ *
FirstEnergy Website....................................................................... *
Item 2. Properties.................................................................................. *
Item 3. Legal Proceedings........................................................................... *
Item 4. Submission of Matters to a Vote of Security Holders......................................... *
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................... *
Item 6. Selected Financial Data..................................................................... *
Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition ...... 1
Item 8. Financial Statements and Supplementary Data................................................. 15
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure........ *
PART III
Item 10. Directors and Executive Officers of the Registrant.......................................... *
Item 11. Executive Compensation...................................................................... *
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Shareholder Matters....................................................................... *
Item 13. Certain Relationships and Related Transactions.............................................. *
Item 14. Controls and Procedures..................................................................... *
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 40
* Indicates the items that have not been revised and are not included in this
Form 10-K/A. Reference is made to the original 10-K, as previously amended,
for the complete text of such items.
THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT NO. 2:
PART II
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
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.
1
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:
2
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 $1.9 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).
3
2003.............. $169
2004.............. 190
2005.............. 217
2006.............. 128
2007.............. 145
2008.............. 163
2009.............. 43
Other Unrecorded Adjustments
This restatement for the three years ended December 31, 2002
also includes adjustments that were not previously recognized. 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 341,117 322,123 408,853 367,714 402,662 410,136
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
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
4
revenues associated with the low-income payment plan now administered by the
Ohio Department of Development; there was also a corresponding reduction in
other operating costs associated with that change. Revenues from kilowatt-hour
sales to wholesale customers declined by $86.7 million in 2001 from 2000, with a
corresponding 76.4% reduction in kilowatt-hour sales.
CHANGES IN KWH SALES 2002 2001
---------------------------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail................................ (23.9)% (14.9)%
Wholesale............................. (12.8)% (76.4)%
---------------------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES......... (18.9)% (26.4)%
=====================================================================
Distribution Deliveries:
Residential........................... 6.1 % -- %
Commercial and industrial............. (6.6)% (3.2)%
---------------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES........... (3.3)% (2.4)%
=====================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $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 $185.7 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))
(IN MILLIONS)
INCREASE (DECREASE)
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) (2.3)
---------------------------------------------------------------------
TOTAL OPERATING EXPENSES AND TAXES......... $(172.7) $(185.7)
---------------------------------------------------------------------
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 $11.8 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.
5
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
$4.6 million in 2002 and by $9.9 million in 2001, compared to the prior year. We
continued to redeem and refinance outstanding debt and preferred stock during
2002 - net redemptions and refinancing activities totaled $291.8 million and
$108.7 million, respectively, and will result in annualized savings of $25.5
million.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements were $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).................... $326.5 $ 467.6
Working capital and other............ (9.3) (102.1)
--------------------------------------------------------------
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
====================================================================
6
In 2001, net cash used for financing activities totaled $192.4
million, primarily due to payment of common stock dividends to FirstEnergy.
We had about $30.8 million of cash and temporary investments
and approximately $288.6 million of short-term indebtedness at the end of 2002.
We had the capability to issue $379.3 million of additional first mortgage bonds
(FMB) on the basis of property additions and retired bonds. We have no
restrictions on the issuance of preferred stock. At the end of 2002, our common
equity as a percentage of capitalization, including debt relating to assets held
for sale, stood at 36% compared to 31% at the end of 2001. The higher common
equity percentage in 2002 compared to 2001 resulted from net redemptions of
preferred stock and long-term debt, the additional equity investment from
FirstEnergy and the increase in retained earnings.
Cash Flows from Investing Activities
Net cash used in investing activities totaled $147 million in
2002. The net cash used for investing resulted from property additions, which
was offset in part by a reduction of the Shippingport Capital Trust investment.
Expenditures for property additions primarily include expenditures supporting
our distribution of electricity and capital expenditures related to Davis-Besse
(see Davis-Besse Restoration).
In 2001, net cash used in investing activities totaled $176
million, principally due to property additions and the sale of property to
affiliates as part of corporate separation and the sale to ATSI discussed above.
Our cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without increasing our net debt and preferred
stock outstanding. Over the next three years, we expect to meet our contractual
obligations with cash from operations. Thereafter, we expect to use a
combination of cash from operations and funds from the capital markets.
LESS THAN 1-3 3-5 MORE THAN
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR YEARS YEARS 5 YEARS
----------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Long-term debt.................. $2,309 $145 $580 $120 $1,464
Short-term borrowings........... 289 289 -- -- --
Preferred stock (1)............. 106 1 2 2 101
Capital leases (2).............. 10 1 2 2 5
Operating leases (2)............ 200 (2) 46 25 131
Purchases (3)................... 413 46 114 100 153
---------------------------------------------------------------------------------------------------------------
Total...................... $3,327 $480 $744 $249 $1,854
===============================================================================================================
(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,
7
2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash
charges related to deferred costs in Pennsylvania, pension and other
post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations),
which were higher than anticipated in the third quarter of 2002. S&P identified
the restart of the Davis-Besse nuclear plant "...without significant delay
beyond April 2003..." as key to maintaining its current debt ratings. S&P also
identified other issues it would continue to monitor including: FirstEnergy's
deleveraging efforts, free cash generated during 2003, the Jersey Central Power
& Light Company rate case, successful hedging of our short power position, and
continued capture of projected merger savings. While we anticipate being
prepared to restart the Davis-Besse plant in the spring of 2003, the Nuclear
Regulatory Commission (NRC) must authorize the unit's restart following a formal
inspection process prior to our returning the unit to service. Significant
delays in the planned date of Davis-Besse's return to service or other factors
(identified above) affecting the speed with which we reduce debt could put
additional pressure on our credit ratings.
Other Obligations
Obligations not included on our Consolidated Balance Sheet
primarily consist of a sale and leaseback arrangement involving the Bruce
Mansfield Plant, which is reflected in the operating lease payments disclosed
above (see Note 2 - Leases). The present value as of December 31, 2002, of this
sale and leaseback operating lease commitments, net of trust investments, total
$156 million.
INTEREST RATE RISK
Our exposure to fluctuations in market interest rates is
reduced since a significant portion of our debt has fixed interest rates, as
noted in the following table. We are subject to the inherent risks related to
refinancing maturing debt by issuing new debt securities. As discussed in Note
2, our investment in the Shippingport Capital Trust effectively reduces future
lease obligations, also reducing interest rate risk. Changes in the market value
of our nuclear decommissioning trust funds had been recognized by making
corresponding changes to the decommissioning liability, as described in Note 1 -
Utility Plant and Depreciation. 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).
8
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).
9
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 (SO(2)) and nitrogen oxide (NO(x)) reduction requirements under the
Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency
(EPA) finalized regulations requiring additional NO(x) reductions in the future
from our Ohio and Pennsylvania facilities. Various regulatory and judicial
actions have since sought to further define NO(x) reduction requirements (see
Note 5 - Environmental Matters). We continue to evaluate our compliance plans
and other compliance options.
Violations of federally approved (SO(2)) 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 SO(2) 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.
10
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
11
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).
12
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.
13
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.
14
THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT NO. 2:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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.
15
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 $6,526,596
========== ==========
* See Note 1(M)
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
16
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)
17
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.
18
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.
19
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.
20
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.
21
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,
22
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 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. In June
2001, the Financial Accounting Standards Board issued
23
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
---- ---- ----
RESTATED RESTATED RESTATED
-------- -------- --------
(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
=================================================================================================
24
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
25
$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.
26
(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:
27
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.
28
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:
29
TRANSITION REVERSAL
COST OF LEASE
INCOME STATEMENT EFFECTS AMORTIZATION OBLIGATIONS(1) TOTAL
------------ -------------- ---------
INCREASE (DECREASE) (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............... $169
2004............... 190
2005............... 217
2006............... 128
2007............... 145
2008............... 163
2009............... 43
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.
30
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
========== ========== ========== ==========
31
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
==========================================================
32
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
33
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
34
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.
35
(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
36
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
37
January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs
created before February 1, 2003 are subject to this interpretation's provisions
beginning in the first interim or annual reporting period after June 15, 2003
(our third quarter of 2003). The FASB also identified transitional disclosure
provisions for all financial statements issued after January 31, 2003.
The Company currently has transactions with entities which may
fall within the scope of this interpretation and which are reasonably possible
of meeting the definition of a VIE in accordance with FIN 46. The Company
currently consolidates the majority of these entities and believe the Company
will continue to consolidate following the adoption of FIN 46. One of these
entities the Company is currently consolidating is the Shippingport Capital
Trust which reacquired a portion of the off-balance sheet debt issued in
connection with the sale and leaseback of our interest in the Bruce Mansfield
Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated
parties and 0.34 percent equity interest by Toledo Edison Capital Corp., an
affiliated company.
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.
38
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 PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS 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 PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS 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:
2002 2001
---- ----
March 31........... 9.2 (1.9)
December 31........ (1.6) (6.0)
39
PART IV
3. EXHIBITS - COMMON EXHIBITS TO CEI AND TE
EXHIBIT
NUMBER
------
2(a) -- Agreement and Plan of Merger between Ohio Edison and Centerior
Energy dated as of September 13, 1996 (Exhibit (2)-1, Form S-4
File No. 333-21011, filed by FirstEnergy).
2(b) -- Merger Agreement by and among Centerior Acquisition Corp.,
FirstEnergy and Centerior (Exhibit (2)-3, Form S-4 File No.
333-21011, filed by FirstEnergy).
4(a) -- Rights Agreement (Exhibit 4, June 25, 1996 Form 8-K, File Nos.
1-9130, 1-2323 and 1-3583).
4(b)(1) -- Form of Note Indenture between Cleveland Electric, Toledo Edison
and The Chase Manhattan Bank, as Trustee dated as of June 13,
1997 (Exhibit 4(c), Form S-4 File No. 333-35931, filed by
Cleveland Electric and Toledo Edison).
4(b)(2) -- Form of First Supplemental Note Indenture between Cleveland
Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee
dated as of June 13, 1997 (Exhibit 4(d), Form S-4 File No.
333-35931, filed by Cleveland Electric and Toledo Edison).
10b(1)(a) -- CAPCO Administration Agreement dated November 1, 1971, as of
September 14, 1967, among the CAPCO Group members regarding the
organization and procedures for implementing the objectives of
the CAPCO Group (Exhibit 5(p), Amendment No. 1, File No. 2-42230,
filed by Cleveland Electric).
10b(1)(b) -- Amendment No. 1, dated January 4, 1974, to CAPCO Administration
Agreement among the CAPCO Group members (Exhibit 5(c)(3), File
No. 2-68906, filed by Ohio Edison).
10b(2) -- CAPCO Transmission Facilities Agreement dated November 1, 1971,
as of September 14, 1967, among the CAPCO Group members regarding
the installation, operation and maintenance of transmission
facilities to carry out the objectives of the CAPCO Group
(Exhibit 5(q), Amendment No. 1, File No. 2-42230, filed by
Cleveland Electric).
10b(2)(1) -- Amendment No. 1 to CAPCO Transmission Facilities Agreement, dated
December 23, 1993 and effective as of January 1, 1993, among the
CAPCO Group members regarding requirements for payment of
invoices at specified times, for payment of interest on
non-timely paid invoices, for restricting adjustment of invoices
after a four-year period, and for revising the method for
computing the Investment Responsibility charge for use of a
member's transmission facilities (Exhibit 10b(2)(1), 1993 Form
10-K, File Nos. 1-9130, 1-2323 and 1-3583).
10b(3) -- CAPCO Basic Operating Agreement As Amended January 1, 1993 among
the CAPCO Group members regarding coordinated operation of the
members' systems (Exhibit 10b(3), 1993 Form 10-K, File Nos.
1-9130, 1-2323 and 1-3583).
10b(4) -- Agreement for the Termination or Construction of Certain
Agreement By and Among the CAPCO Group members, dated December
23, 1993 and effective as of September 1, 1980 (Exhibit 10b(4),
1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583).
10b(5) -- Construction Agreement, dated July 22, 1974, among the CAPCO
Group members and relating to the Perry Nuclear Plant (Exhibit 5
(yy), File No. 2-52251, filed by Toledo Edison).
10b(6) -- Contract, dated as of December 5, 1975, among the CAPCO Group
members for the construction of Beaver Valley Unit No. 2 (Exhibit
5 (g), File No. 2-52996, filed by Cleveland Electric).
10b(7) -- Amendment No. 1, dated May 1, 1977, to Contract, dated as of
December 5, 1975, among the CAPCO Group members for the
construction of Beaver Valley Unit No. 2 (Exhibit 5(d)(4), File
No. 2-60109, filed by Ohio Edison).
40
10d(1)(a) -- Form of Collateral Trust Indenture among CTC Beaver Valley
Funding Corporation, Cleveland Electric, Toledo Edison and Irving
Trust Company, as Trustee (Exhibit 4(a), File No. 33-18755, filed
by Cleveland Electric and Toledo Edison).
10d(1)(b) -- Form of Supplemental Indenture to Collateral Trust Indenture
constituting Exhibit 10d(1)(a) above, including form of Secured
Lease Obligation bond (Exhibit 4(b), File No. 33-18755, filed by
Cleveland Electric and Toledo Edison).
10d(1)(c) -- Form of Collateral Trust Indenture among Beaver Valley II Funding
Corporation, The Cleveland Electric Illuminating Company and The
Toledo Edison Company and The Bank of New York, as Trustee
(Exhibit (4)(a), File No. 33-46665, filed by Cleveland Electric
and Toledo Edison).
10d(1)(d) -- Form of Supplemental Indenture to Collateral Trust Indenture
constituting Exhibit 10d(1)(c) above, including form of Secured
Lease Obligation Bond (Exhibit (4)(b), File No. 33-46665, filed
by Cleveland Electric and Toledo Edison).
10d(2)(a) -- Form of Collateral Trust Indenture among CTC Mansfield Funding
Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder
Bank & Trust Company, as Trustee (Exhibit 4(a), File No.
33-20128, filed by Cleveland Electric and Toledo Edison).
10d(2)(b) -- Form of Supplemental Indenture to Collateral Trust Indenture
constituting Exhibit 10d(2)(a) above, including forms of Secured
Lease Obligation bonds (Exhibit 4(b), File No. 33-20128, filed by
Cleveland Electric and Toledo Edison).
10d(3)(a) -- Form of Facility Lease dated as of September 15, 1987 between The
First National Bank of Boston, as Owner Trustee under a Trust
Agreement dated as of September 15, 1987 with the limited
partnership Owner Participant named therein, Lessor, and
Cleveland Electric and Toledo Edison, Lessee (Exhibit 4(c), File
No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(3)(b) -- Form of Amendment No. 1 to Facility Lease constituting Exhibit
10d(3)(a) above (Exhibit 4(e), File No. 33-18755, filed by
Cleveland Electric and Toledo Edison).
10d(4)(a) -- Form of Facility Lease dated as of September 15, 1987 between The
First National Bank of Boston, as Owner Trustee under a Trust
Agreement dated as of September 15, 1987 with the corporate Owner
Participant named therein, Lessor, and Cleveland Electric and
Toledo Edison, Lessees (Exhibit 4(d), File No. 33-18755, filed by
Cleveland Electric and Toledo Edison).
10d(4)(b) -- Form of Amendment No. 1 to Facility Lease constituting Exhibit
10d(4)(a) above (Exhibit 4(f), File No. 33-18755, filed by
Cleveland Electric and Toledo Edison).
10d(5)(a) -- Form of Facility Lease dated as of September 30, 1987 between
Meridian Trust Company, as Owner Trustee under a Trust Agreement
dated as of September 30, 1987 with the Owner Participant named
therein, Lessor, and Cleveland Electric and Toledo Edison,
Lessees (Exhibit 4(c), File No. 33-20128, filed by Cleveland
Electric and Toledo Edison).
10d(5)(b) -- Form of Amendment No. 1 to the Facility Lease constituting
Exhibit 10d(5)(a) above (Exhibit 4(f), File No. 33-20128, filed
by Cleveland Electric and Toledo Edison).
10d(6)(a) -- Form of Participation Agreement dated as of September 15, 1987
among the limited partnership Owner Participant named therein,
the Original Loan Participants listed in Schedule 1 thereto, as
Original Loan Participants, CTC Beaver Valley Fund Corporation,
as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company, as Indenture Trustee, and
Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a),
File No. 33-18755, filed by Cleveland Electric And Toledo
Edison).
10d(6)(b) -- Form of Amendment No. 1 to Participation Agreement constituting
Exhibit 10d(6)(a) above (Exhibit 28(c), File No. 33-18755, filed
by Cleveland Electric and Toledo Edison).
10d(7)(a) -- Form of Participation Agreement dated as of September 15, 1987
among the corporate Owner Participant named therein, the Original
Loan Participants listed in Schedule 1 thereto, as Owner Loan
Participants, CTC Beaver Valley Funding Corporation, as Funding
Corporation, The First National Bank of Boston, as Owner Trustee,
Irving Trust Company, as Indenture Trustee, and
41
Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(b),
File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
10d(7)(b) -- Form of Amendment No. 1 to Participation Agreement constituting
Exhibit 10d(7)(a) above (Exhibit 28(d), File No. 33-18755, filed
by Cleveland Electric and Toledo Edison).
10d(8)(a) -- Form of Participation Agreement dated as of September 30, 1987
among the Owner Participant named therein, the Original Loan
Participants listed in Schedule II thereto, as Owner Loan
Participants, CTC Mansfield Funding Corporation, Meridian Trust
Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as
Indenture Trustee, and Cleveland Electric and Toledo Edison, as
Lessees (Exhibit 28(a), File No. 33-0128, filed by Cleveland
Electric and Toledo Edison).
10d(8)(b) -- Form of Amendment No. 1 to the Participation Agreement
constituting Exhibit 10d(8)(a) above (Exhibit 28(b), File No.
33-20128, filed by Cleveland Electric and Toledo Edison).
10d(9) -- Form of Ground Lease dated as of September 15, 1987 between
Toledo Edison, Ground Lessor, and The First National Bank of
Boston, as Owner Trustee under a Trust Agreement dated as of
September 15, 1987 with the Owner Participant named therein,
Tenant (Exhibit 28(e), File No. 33-18755, filed by Cleveland
Electric and Toledo Edison).
10d(10) -- Form of Site Lease dated as of September 30, 1987 between Toledo
Edison, Lessor, and Meridian Trust Company, as Owner Trustee
under a Trust Agreement dated as of September 30, 1987 with the
Owner Participant named therein, Tenant (Exhibit 28(c), File No.
33-20128, filed by Cleveland Electric and Toledo Edison).
10d(11) -- Form of Site Lease dated as of September 30, 1987 between
Cleveland Electric, Lessor, and Meridian Trust Company, as Owner
Trustee under a Trust Agreement dated as of September 30, 1987
with the Owner Participant named therein, Tenant (Exhibit 28(d),
File No. 33-20128, filed by Cleveland Electric and Toledo
Edison).
10d(12) -- Form of Amendment No. 1 to the Site Leases constituting Exhibits
10d(10) and 10d(11) above (Exhibit 4(f), File No. 33-20128, filed
by Cleveland Electric and Toledo Edison).
10d(13) -- Form of Assignment, Assumption and Further Agreement dated as of
September 15, 1987 among The First National Bank of Boston, as
Owner Trustee under a Trust Agreement dated as of September 15,
1987 with the Owner Participant named therein, Cleveland
Electric, Duquesne, Ohio Edison, Pennsylvania Power and Toledo
Edison (Exhibit 28(f), File No. 33-18755, filed by Cleveland
Electric and Toledo Edison).
10d(14) -- Form of Additional Support Agreement dated as of September 15,
1987 between The First National Bank of Boston, as Owner Trustee
under a Trust Agreement dated as of September 15, 1987 with the
Owner Participant named therein, and Toledo Edison (Exhibit
28(g), File No. 33-18755, filed by Cleveland Electric and Toledo
Edison).
10d(15) -- Form of Support Agreement dated as of September 30, 1987 between
Meridian Trust Company, as Owner Trustee under a Trust Agreement
dated as of September 30, 1987 with the Owner Participant named
therein, Toledo Edison, Cleveland Electric, Duquesne, Ohio Edison
and Pennsylvania Power (Exhibit 28(e), File No. 33-20128, filed
by Cleveland Electric and Toledo Edison).
10d(16) -- Form of Indenture, Bill of Sale, Instrument of Transfer and
Severance Agreement dated as of September 30, 1987 between Toledo
Edison, Seller, and The First National Bank of Boston, as Owner
Trustee under a Trust Agreement dated as of September 15, 1987
with the Owner Participant named therein, Buyer (Exhibit 28(h),
File No. 33-18755, filed by Cleveland Electric and Toledo
Edison).
10d(17) -- Form of Bill of Sale, Instrument of Transfer and Severance
Agreement dated as of September 30, 1987 between Toledo Edison,
Seller, and Meridian Trust Company, as Owner Trustee under a
Trust Agreement dated as of September 30, 1987 with the Owner
Participant named therein, Buyer (Exhibit 28(f), File No.
33-20128, filed by Cleveland Electric and Toledo Edison).
42
10d(18) -- Form of Bill of Sale, Instrument of Transfer and Severance
Agreement dated as of September 30, 1987 between Cleveland
Electric, Seller, and Meridian Trust Company, as Owner Trustee
under a Trust Agreement dated as of September 30, 1987 with the
Owner Participant named therein, Buyer (Exhibit 28(g), File No.
33-20128, filed by Cleveland Electric and Toledo Edison).
10d(19) -- Forms of Refinancing Agreement, including exhibits thereto, among
the Owner Participant named therein, as Owner Participant, CTC
Beaver Valley Funding Corporation, as Funding Corporation, Beaver
Valley II Funding Corporation, as New Funding Corporation, The
Bank of New York, as Indenture Trustee, The Bank of New York, as
New Collateral Trust Trustee, and The Cleveland Electric
Illuminating Company and The Toledo Edison Company, as Lessees
(Exhibit (28)(e)(i), File No. 33-46665, filed by Cleveland
Electric and Toledo Edison).
10d(20)(a) -- Form of Amendment No. 2 to Facility Lease among Citicorp
Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit
10(a), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(20)(b) -- Form of Amendment No. 3 to Facility Lease among Citicorp
Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit
10(b), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(21)(a) -- Form of Amendment No. 2 to Facility Lease among US West Financial
Services, Inc., Cleveland Electric and Toledo Edison (Exhibit
10(c), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(21)(b) -- Form of Amendment No. 3 to Facility Lease among US West Financial
Services, Inc., Cleveland Electric and Toledo Edison (Exhibit
10(d), Form S-4 File No. 333-47651, filed by Cleveland Electric).
10d(22) -- Form of Amendment No. 2 to Facility Lease among Midwest Power
Company, Cleveland Electric and Toledo Edison (Exhibit 10(e),
Form S-4 File No. 333-47651, filed by Cleveland Electric).
10e(1) -- Centerior Energy Corporation Equity Compensation Plan (Exhibit
99, Form S-8, File No. 33-59635).
3. EXHIBITS - CLEVELAND ELECTRIC ILLUMINATING (CEI)
3a -- Amended Articles of Incorporation of CEI, as amended, effective May 28,
1993 (Exhibit 3a, 1993 Form 10-K, File No. 1-2323).
3b -- Regulations of CEI, dated April 29, 1981, as amended effective October 1,
1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-2323).
3c -- Amended and Restated Code of Regulations, dated March 15, 2002.
(B)4b(1) -- Mortgage and Deed of Trust between CEI and Guaranty Trust Company
of New York (now The Chase Manhattan Bank (National
Association)), as Trustee, dated July 1, 1940 (Exhibit 7(a), File
No. 2-4450).
Supplemental Indentures between CEI and the Trustee,
supplemental to Exhibit 4b(1), dated as follows:
4b(2) -- July 1, 1940 (Exhibit 7(b), File No. 2-4450).
4b(3) -- August 18, 1944 (Exhibit 4(c), File No. 2-9887).
4b(4) -- December 1, 1947 (Exhibit 7(d), File No. 2-7306).
4b(5) -- September 1, 1950 (Exhibit 7(c), File No. 2-8587).
4b(6) -- June 1, 1951 (Exhibit 7(f), File No. 2-8994).
4b(7) -- May 1, 1954 (Exhibit 4(d), File No. 2-10830).
4b(8) -- March 1, 1958 (Exhibit 2(a)(4), File No. 2-13839).
4b(9) -- April 1, 1959 (Exhibit 2(a)(4), File No. 2-14753).
4b(10) -- December 20, 1967 (Exhibit 2(a)(4), File No. 2-30759).
4b(11) -- January 15, 1969 (Exhibit 2(a)(5), File No. 2-30759).
4b(12) -- November 1, 1969 (Exhibit 2(a)(4), File No. 2-35008).
4b(13) -- June 1, 1970 (Exhibit 2(a)(4), File No. 2-37235).
43
4b(14) -- November 15, 1970 (Exhibit 2(a)(4), File No. 2-38460).
4b(15) -- May 1, 1974 (Exhibit 2(a)(4), File No. 2-50537).
4b(16) -- April 15, 1975 (Exhibit 2(a)(4), File No. 2-52995).
4b(17) -- April 16, 1975 (Exhibit 2(a)(4), File No. 2-53309).
4b(18) -- May 28, 1975 (Exhibit 2(c), June 5, 1975 Form 8-A, File No. 1-2323).
4b(19) -- February 1, 1976 (Exhibit 3(d)(6), 1975 Form 10 K, File No. 1-2323).
4b(20) -- November 23, 1976 (Exhibit 2(a)(4), File No. 2-57375).
4b(21) -- July 26, 1977 (Exhibit 2(a)(4), File No. 2-59401).
4b(22) -- September 7, 1977 (Exhibit 2(a)(5), File No. 2-67221).
4b(23) -- May 1, 1978 (Exhibit 2(b), June 30, 1978 Form 10-Q, File No. 1-2323).
4b(24) -- September 1, 1979 (Exhibit 2(a), September 30, 1979 Form 10-Q, File No. 1-2323).
4b(25) -- April 1, 1980 (Exhibit 4(a)(2), September 30, 1980 Form 10-Q, File No. 1-2323).
4b(26) -- April 15, 1980 (Exhibit 4(b), September 30, 1980 Form 10-Q, File No. 1-2323).
4b(27) -- May 28, 1980 (Exhibit 2(a)(4), Amendment No. 1, File No. 2-67221).
4b(28) -- June 9, 1980 (Exhibit 4(d), September 30, 1980 Form 10-Q, File No. 1-2323).
4b(29) -- December 1, 1980 (Exhibit 4(b)(29), 1980 Form 10-K, File No. 1-2323).
4b(30) -- July 28, 1981 (Exhibit 4(a), September 30, 1981, Form 10-Q, File No. 1-2323).
4b(31) -- August 1, 1981 (Exhibit 4(b), September 30, 1981, Form 10-Q, File No. 1-2323).
4b(32) -- March 1, 1982 (Exhibit 4(b)(3), Amendment No. 1, File No. 2-76029).
4b(33) -- July 15, 1982 (Exhibit 4(a), September 30, 1982 Form 10-Q, File No. 1-2323).
4b(34) -- September 1, 1982 (Exhibit 4(a)(1), September 30, 1982 Form 10-Q, File No. 1-2323).
4b(35) -- November 1, 1982 (Exhibit (a)(2), September 30, 1982 Form 10-Q, File No. 1-2323).
4b(36) -- November 15, 1982 (Exhibit 4(b)(36), 1982 Form 10-K, File No. 1-2323).
4b(37) -- May 24, 1983 (Exhibit 4(a), June 30, 1983 Form 10-Q, File No. 1-2323).
4b(38) -- May 1, 1984 (Exhibit 4, June 30, 1984 Form 10-Q, File No. 1-2323).
4b(39) -- May 23, 1984 (Exhibit 4, May 22, 1984 Form 8-K, File No. 1-2323).
4b(40) -- June 27, 1984 (Exhibit 4, June 11, 1984 Form 8-K, File No. 1-2323).
4b(41) -- September 4, 1984 (Exhibit 4b(41), 1984 Form 10-K, File No. 1-2323).
4b(42) -- November 14, 1984 (Exhibit 4b(42), 1984 Form 10 K, File No. 1-2323).
4b(43) -- November 15, 1984 (Exhibit 4b(43), 1984 Form 10-K, File No. 1-2323).
4b(44) -- April 15, 1985 (Exhibit 4(a), May 8, 1985 Form 8-K, File No. 1-2323).
4b(45) -- May 28, 1985 (Exhibit 4(b), May 8, 1985 Form 8-K, File No. 1-2323).
4b(46) -- August 1, 1985 (Exhibit 4, September 30, 1985 Form 10-Q, File No. 1-2323).
4b(47) -- September 1, 1985 (Exhibit 4, September 30, 1985 Form 8-K, File No. 1-2323).
4b(48) -- November 1, 1985 (Exhibit 4, January 31, 1986 Form 8-K, File No. 1-2323).
4b(49) -- April 15, 1986 (Exhibit 4, March 31, 1986 Form 10-Q, File No. 1-2323).
4b(50) -- May 14, 1986 (Exhibit 4(a), June 30, 1986 Form 10-Q, File No. 1-2323).
4b(51) -- May 15, 1986 (Exhibit 4(b), June 30, 1986 Form 10-Q, File No. 1-2323).
4b(52) -- February 25, 1987 (Exhibit 4b(52), 1986 Form 10-K, File No. 1-2323).
4b(53) -- October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-2323).
4b(54) -- February 24, 1988 (Exhibit 4b(54), 1987 Form 10-K, File No. 1-2323).
4b(55) -- September 15, 1988 (Exhibit 4b(55), 1988 Form 10-K, File No. 1-2323).
4b(56) -- May 15, 1989 (Exhibit 4(a)(2)(i), File No. 33-32724).
4b(57) -- June 13, 1989 (Exhibit 4(a)(2)(ii), File No. 33-32724).
4b(58) -- October 15, 1989 (Exhibit 4(a)(2)(iii), File No. 33-32724).
4b(59) -- January 1, 1990 (Exhibit 4b(59), 1989 Form 10-K, File No. 1-2323).
4b(60) -- June 1, 1990 (Exhibit 4(a). September 30, 1990 Form 10-Q, File No. 1-2323).
4b(61) -- August 1, 1990 (Exhibit 4(b), September 30, 1990 Form 10-Q, File No. 1-2323).
4b(62) -- May 1, 1991 (Exhibit 4(a), June 30, 1991 Form 10-Q, File No. 1-2323).
4b(63) -- May 1, 1992 (Exhibit 4(a)(3), File No. 33-48845).
4b(64) -- July 31, 1992 (Exhibit 4(a)(3), File No. 33-57292).
4b(65) -- January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No. 1-2323).
4b(66) -- February 1, 1993 (Exhibit 4b(66), 1992 Form 10-K, File No. 1-2323).
4b(67) -- May 20, 1993 (Exhibit 4(a), July 14, 1993 Form 8-K, File No. 1-2323).
4b(68) -- June 1, 1993 (Exhibit 4(b), July 14, 1993 Form 8-K, File No. 1-2323).
4b(69) -- September 15, 1994 (Exhibit 4(a), September 30, 1994 Form 10-Q, File No. 1-2323).
4b(70) -- May 1, 1995 (Exhibit 4(a), September 30, 1995 Form 10-Q, File No. 1-2323).
4b(71) -- May 2, 1995 (Exhibit 4(b), September 30, 1995 Form 10-Q, File No. 1-2323).
4b(72) -- June 1, 1995 (Exhibit 4(c), September 30, 1995 Form 10-Q, File No. 1-2323).
4b(73) -- July 15, 1995 (Exhibit 4b(73), 1995 Form 10-K, File No. 1-2323).
44
4b(74) -- August 1, 1995 (Exhibit 4b(74), 1995 Form 10-K, File No. 1-2323).
4b(75) -- June 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-35931, filed by
Cleveland Electric and Toledo Edison).
4b(76) -- October 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-47651, filed by
Cleveland Electric).
4b(77) -- June 1, 1998 (Exhibit 4b(77), Form S-4 File No. 333-72891).
4b(78) -- October 1, 1998 (Exhibit 4b(78), Form S-4 File No. 333-72891).
4b(79) -- October 1, 1998 (Exhibit 4b(79), Form S-4 File No. 333-72891).
4b(80) -- February 24, 1999 (Exhibit 4b(80), Form S-4 File No. 333-72891).
4b(81) -- September 29, 1999. (Exhibit 4b(81), 1999 Form 10-K, File No. 1-2323).
4b(82) -- January 15, 2000. (Exhibit 4b(82), 1999 Form 10-K, File No. 1-2323).
4b(83) -- May 15, 2002
4b(84) -- October 1, 2002
4d -- Form of Note Indenture between Cleveland Electric and The Chase Manhattan
Bank, as Trustee dated as of October 24, 1997 (Exhibit 4(b), Form S-4 File
No. 333-47651, filed by Cleveland Electric).
4d(1) -- Form of Supplemental Note Indenture between Cleveland Electric
and The Chase Manhattan Bank, as Trustee dated as of October 24,
1997 (Exhibit 4(c), Form S-4 File No. 333-47651, filed by
Cleveland Electric).
10-1 -- Administration Agreement between the CAPCO Group dated as of September 14,
1967. (Registration No. 2-43102, Exhibit 5(c)(2).)
10-2 -- Amendment No. 1 dated January 4, 1974 to Administration Agreement
between the CAPCO Group dated as of September 14, 1967. (Registration No.
2-68906, Exhibit 5(c)(3).)
10-3 -- Transmission Facilities Agreement between the CAPCO Group dated as of
September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3).)
10-4 -- Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities
Agreement between the CAPCO Group dated as of September 14, 1967.
(1993 Form 10-K, Exhibit 10-4.)
10-5 -- Agreement for the Termination or Construction of
Certain Agreements effective September 1, 1980, October
15, 1997 (Exhibit 4(a), Form S-4 File No. 333-47651,
filed by Cleveland Electric).
* 12.3 -- Consolidated fixed charge ratios.
* 13.2 -- CEI 2002 Annual Report to Stockholders. (Only those portions expressly
incorporated by reference in this Form 10-K/A are to be deemed "filed"
with the SEC.)
21.2 -- List of Subsidiaries of the Registrant at December 31, 2002.
* 31.1 -- Certification letter from chief executive officer, as adopted pursuant
to Section 302 of the Sarbanes-Oxley Act.
* 31.2 -- Certification letter from chief financial officer, as adopted pursuant
to Section 302 or the Sarbanes-Oxley Act.
* 32 -- Certification letter from chief executive officer and chief financial
officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
* Indicates revised exhibits included in this Form 10-K/A in electronic
format. Reference is made to the original 10-K for the other exhibits
filed therewith.
45
REPORTS ON FORM 8-K
CEI
CEI filed fourteen reports on Form 8-K since September 30, 2002. A
report dated October 7, 2002 reported updated cost and schedule estimates
associated with efforts to return Davis-Besse Nuclear Power Station to service.
A report dated October 31, 2002 reported updated information associated with
Davis-Besse restoration efforts. A report dated December 20, 2002 reported that
FirstEnergy subsidiaries would retain ownership of four power plants previously
planned to be sold. A report dated January 17, 2003 reported updated information
related with efforts to prepare Davis-Besse for a safe and reliable return to
service. A report dated March 11, 2003 reported updated Davis-Besse information
including the installation of the new reactor head on the reactor vessel. A
report dated March 17, 2003 reported updated Davis-Besse information. A report
dated April 16, 2003 reported updated Davis-Besse information. A report dated
May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated
information including Davis-Besse updated ready for restart schedule. A report
dated May 9, 2003 reported updated Davis-Besse information. A report dated June
5, 2003 reported updated Davis Besse information. A report dated July 24, 2003,
reported updates to the schedule and cost estimates for Davis Besse. A report
dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE
financial statements and restatement and reaudit of 2001 CEI and TE financial
statements. A report dated August 7, 2003 reported the pending restatement and
reaudit of 2000 CEI and TE financial statements. A report dated September 12,
2003 reported that FE, OE, CEI and TE have received an informal data request
from the Securities and Exchange Commission related to the recent restatement of
their 2002 financial statements.
46
REPORT OF INDEPENDENT AUDITORS ON
FINANCIAL STATEMENT SCHEDULES
To the Stockholders and Board of Directors of The Cleveland Electric
Illuminating Company:
Our audits of the consolidated financial statements referred to in our report
dated August 18, 2003 appearing in the restated 2002 Annual Report to
Shareholders of The Cleveland Electric Illuminating Company (which report and
consolidated financial statements are incorporated by reference in this Form
10-K/A) also included an audit of the financial statement schedules listed in
Item 15(a)(2) of this Form 10-K/A. In our opinion, these financial statement
schedules present fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
47
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
----------------------
Registrant
/s/ Harvey L. Wagner
-----------------------------------
Harvey L. Wagner
Vice President and Controller
Chief Accounting Officer
Date: September 24, 2003
48