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.
----------- ----------------------------------- ------------------
1-3583 THE TOLEDO EDISON COMPANY 34-4375005
(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 Toledo Edison Cumulative Preferred Stock, par value
Company $100 per share:
4.25% Series American Stock Exchange
Cumulative Preferred Stock, par value
$25 per share:
$2.365 Series All series registered on
Adjustable Rate, Series A New York Stock Exchange
Adjustable Rate, Series B
First Mortgage Bonds:
8% Series due 2003 New 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 Toledo Edison Company, $5 par value 39,133,887
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 $53 $114
2004 71 131
2005 99 151
2006 76 95
2007 75 68
Under the heading "Results of Operations":
In the sixth sentence of the second paragraph, the text "..but revenues
from electricity throughput decreased by $11.1 million in 2002 from the
prior year due to lower unit prices" should have read "... and revenues
from electricity throughput increased by $5.7 million in 2002 from the
prior year".
Under the subheading "Operating Expenses and Taxes":
In the second sentence of the first paragraph, the decrease in
total 2001 operating expenses and taxes of $18.0 million
should have read $35.9 million.
In the fourth sentence of the second paragraph, the increase
in other operating costs of $7.3 million should have read $7.2
million.
Under the heading "Capital Resources and Liquidity":
Under the subheading "Cash Flows from Operating Activities":
In the table, 2002 cash earnings and working capital and other
is corrected as follows:
(IN MILLIONS)
AS ORIGINALLY FILED AS CORRECTED
------------------- ------------
Cash earnings $111 $142
Working capital and other 45 14
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 $53 $114
2004 71 131
2005 99 151
2006 76 95
2007 75 68
Under Note 3 - CAPITALIZATION:
Under the subheading "(E) COMPREHENSIVE INCOME":
In the second sentence, the unrealized gains of $(5,997)
should have read $1.1 million.
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............................. 39
* 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 TOLEDO EDISON 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. Toledo Edison Company (TE)
continues to deliver power to homes and businesses through our existing
distribution system and maintain the "provider of last resort" (PLR) obligation
under our rate plan. As a result of the transition plan, FirstEnergy's electric
utility operating companies (EUOC) entered into power supply agreements whereby
FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation,
and leases EUOC fossil generating facilities. We are a "full requirements"
customer of FES to enable us to meet our PLR responsibilities in our service
area.
The effect on TE'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 ........... $180.9 $ -- $180.9
Generating units rent ..................... 14.0 -- 14.0
Ground lease with ATSI .................... -- (0.2) (0.2)
---------------------------------------------------------------------------------------
TOTAL OPERATING REVENUES EFFECT ........... $194.9 $ (0.2) $194.7
=======================================================================================
Operating Expenses and Taxes:
Fossil fuel costs ......................... $(39.8)(a) $ -- $(39.8)
Purchased power costs ..................... 388.0(b) -- 388.0
Other operating costs ..................... (21.6)(a) 7.6(d) (14.0)
Provision for depreciation and
amortization .............................. -- (2.7)(e) (2.7)
General taxes ............................. (2.0)(c) (3.3)(e) (5.3)
Income taxes .............................. (50.4) 0.1 (50.3)
---------------------------------------------------------------------------------------
TOTAL OPERATING EXPENSES EFFECT ........... $274.2 $ 1.7 $275.9
=======================================================================================
OTHER INCOME ................................ $ -- $ 2.0(f) $ 2.0
=======================================================================================
(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, TE 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
2007.
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, 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 the previously recorded regulatory assets recovered under the
transition period through the end of 2007.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between
Ohio Edison Company (OE) and Centerior Energy Corporation (Centerior). The
merger was accounted for as an acquisition of Centerior, the parent company of
TE, 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 statements to record additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above-market lease liability
for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE 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 $111 million
associated with Beaver Valley Unit 2 will be amortized through the end of the
lease term in 2017 (approximately $5.7 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 $298 million associated with the Bruce Mansfield Plant is being reversed
through the end of 2016 (approximately $18.9 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 will be included in
the Company's revised amortization schedule for regulatory assets and amortized
through the end of the recovery period in 2007.
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
$4.3 million to retained earnings as of January 1, 2000. The after-tax effect of
these items for the three years ended December 31, 2002 was 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 $ -- $ (5,700) $ (5,700)
Other operating expenses -- (18,900) (18,900)
Provision for depreciation and amortization 28,400 40,200 68,600
Income taxes (12,559) (6,372) (18,931)
-------- -------- --------
Total expense $ 15,841 $ 9,228 $ 25,069
======== ======== ========
Net income effect $(15,841) $ (9,228) $(25,069)
======== ======== ========
Year ended December 31, 2001
Nuclear operating expenses $ -- $ (5,700) $ (5,700)
Other operating expenses -- (18,900) (18,900)
Provision for depreciation and amortization 13,600 33,000 46,600
Income taxes (5,619) (3,177) (8,796)
-------- -------- --------
Total expense $ 7,981 $ 5,223 $ 13,204
======== ======== ========
Net income effect $ (7,981) $ (5,223) $(13,204)
======== ======== ========
Year ended December 31, 2000
Nuclear operating expenses $ -- $ (5,700) $ (5,700)
Other operating expenses -- -- --
Provision for depreciation and amortization -- 1,600 1,600
Income taxes -- 2,371 2,371
-------- -------- --------
Total expense $ -- $ (1,729) $ (1,729)
======== ======== ========
Net income effect $ -- $ 1,729 $ 1,729
======== ======== ========
(1) The provision for depreciation and amortization in each of 2001 and
2000 includes goodwill amortization of $1.6 million.
In addition, the impact increased the following balances in
the consolidated balance sheet as of January 1, 2000:
(IN THOUSANDS)
Goodwill $ 61,990
Regulatory assets 298,000
----------
Total assets $ 359,990
==========
Other current liabilities $ 24,600
Deferred income taxes (41,059)
Other deferred credits 372,100
----------
Total liabilities $355,641
==========
Retained earnings $ 4,349
==========
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 $(15.5) $(45.3) $24.6 $(36.2) $(21.4)
2004 (7.1) (52.9) 24.6 (35.4) (20.9)
2005 9.6 (61.9) 24.6 (27.7) (16.3)
2006 20.2 (39.3) 24.6 5.5 3.2
2007 33.6 (27.0) 24.6 31.2 18.4
(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 2007 (in millions).
2003.............. $114
2004.............. 131
2005.............. 151
2006.............. 95
2007.............. 68
3
Other Unrecorded Adjustments
This restatement for the years ended December 31, 2002, 2001
and 2000 also includes adjustments that were not previously recognized that
principally related to an adjustment to unbilled revenues in 2001 with the
corresponding impact in 2002. The net income impact by year was $7.2 million in
2002, $(7.0) million in 2001 and $(0.8) 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 EXCEPT PER SHARE AMOUNTS)
Revenues $ 987,645 $ 996,045 $1,094,903 $1,086,503 $ 954,947 $ 954,947
Expenses 932,467 959,346 989,419 1,000,539 761,533 760,622
Other income 13,329 13,329 15,652 15,652 8,669 8,669
---------------------------------------------------------------------------------------------------------------------------------
Income before net interest
charges 68,507 50,028 121,136 101,616 202,083 202,994
Net interest charges 55,170 55,170 58,225 58,925 64,850 64,850
---------------------------------------------------------------------------------------------------------------------------------
Net income 13,337 (5,142) 62,911 42,691 137,233 138,144
Preferred stock dividend
requirements 11,356 10,756 16,135 16,135 16,247 16,247
---------------------------------------------------------------------------------------------------------------------------------
Earnings on common stock $ 1,981 $ (15,898) $ 46,776 $ 26,556 $ 120,986 $ 121,897
=================================================================================================================================
RESULTS OF OPERATIONS
Earnings on common stock decreased to a loss of $15.9 million
in 2002 from $26.6 million in 2001 and $121.9 million in 2000. Excluding the
effects of the corporate restructuring shown in the table above, earnings on
common stock decreased by 13.2% in 2001 from 2000.
Operating revenues decreased by $90.5 million or 8.3% in 2002,
compared with 2001. The lower revenues reflect 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 11.4% in 2002 from the prior year, with declines in all customer
sectors (residential, commercial and industrial), resulting in a $34.4 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 17.0% in 2002 from 5.6% in 2001. Distribution deliveries
increased 0.8% in 2002, compared with 2001 and revenues from electricity
throughput increased by $5.7 million in 2002 from the prior year. The higher
distribution deliveries resulted from additional residential and commercial
demand due to warmer summer weather that was more than offset by the effect that
continued sluggishness in the economy had on demand by the industrial customers.
Transition plan incentives, provided to customers to encourage switching to
alternative energy providers, further reduced operating revenues by $15.0
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 $45.1
million in 2002 compared to 2001, due to lower kilowatt-hour sales and a decline
in market prices. Reduced wholesale kilowatt-hour sales resulted principally
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 $63.1 million or 6.6% in 2001 from
2000 following a $33.8 million increase in 2000 from the prior year. Customer
choice in Ohio and the influence of a declining national economy on our regional
business activity combined to lower operating revenues. Sales of electric
generation provided by other suppliers in our service area represented 5.6% of
total energy delivered in 2001. Retail generation sales declined in all customer
categories resulting in an overall 4.0% reduction in kilowatt-hour sales from
the prior year. Distribution deliveries increased 1.7% in 2001 from the prior
year despite the weaker national economic environment. 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 $8.0 million in 2001, compared to 2000. Operating revenues were
also lower in 2001 from the prior year due to the absence of revenues associated
with the low-income payment plan now administered by the Ohio Department of
Development; there was also a corresponding reduction in other operating costs
associated with that change. Revenues from kilowatt-hour sales to wholesale
customers declined by $36.5 million in 2001 from 2000, with a corresponding
37.2% reduction in kilowatt-hour sales.
4
CHANGES IN KWH SALES 2002 2001
---------------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail .......................... (11.4)% (4.0)%
Wholesale ....................... (27.6)% (37.2)%
--------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES ... (19.2)% (11.8)%
========================================================
Distribution Deliveries:
Residential ..................... 7.5 % 3.4 %
Commercial and industrial ....... (1.0)% 1.1 %
--------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES ..... 0.8 % 1.7 %
========================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $41.2 million
in 2002 and increased by $239.9 million in 2001 from 2000. Excluding the effects
of restructuring, total 2001 operating expenses and taxes were $35.9 million
lower than the prior year. The following table presents changes from the prior
year by expense category excluding the impact of restructuring.
OPERATING EXPENSES AND TAXES - CHANGES 2002 2001
------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
INCREASE (DECREASE) (IN MILLIONS)
Fuel and purchased power ..................... $(90.5) $(49.8)
Nuclear operating costs ...................... 96.8 (16.5)
Other operating costs ........................ 7.2 (8.9)
-----------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES ... 13.5 (75.2)
Provision for depreciation and amortization .. (14.7) 73.0
General taxes ................................ (4.6) (27.7)
Income taxes ................................. (35.4) (6.0)
-----------------------------------------------------------------------
TOTAL OPERATING EXPENSES AND TAXES ......... $(41.2) $(35.9)
=======================================================================
Lower fuel and purchased power costs in 2002, compared to
2001, resulted from a $69.0 million reduction in purchased power from FES,
reflecting lower kilowatt-hours purchased due to reduced kilowatt-hour sales and
lower unit prices. Nuclear operating costs increased by $96.8 million in 2002,
primarily due to approximately $55.9 million of incremental Davis-Besse
maintenance costs related to the extended outage (see Davis-Besse Restoration).
During 2002, costs also included amounts incurred for refueling outages at two
nuclear plants (Beaver Valley Unit 2 and Davis-Besse), compared to only one
outage (Perry) in 2001. The $7.2 million increase in other operating costs in
2002 resulted principally from higher employee benefit costs, employee severance
costs and uncollectible accounts expense.
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. There was one less nuclear
refueling outage in 2001, compared to 2000, resulting in a $16.5 million
decrease in nuclear operating costs from the prior year. Other operating costs
decreased by $8.9 million in 2001 from the prior year, due to a reduction in
low-income payment plan customer costs, decreased storm damage costs and the
absence of costs incurred in 2000 related to the development of a distribution
communications system.
Charges for depreciation and amortization decreased by $14.7
million in 2002 from 2001. This decrease reflects higher shopping incentive
deferrals and tax-related deferrals under TE's transition plan and the cessation
of goodwill amortization beginning January 1, 2002, upon implementation SFAS 142
TE's goodwill amortization in 2001 totaled $14.0 million. Depreciation and
amortization increased by $73.0 million in 2001 from the prior year due to
incremental transition cost amortization under our transition plan, partially
offset by new deferrals for shopping incentives.
General taxes decreased by $4.6 million in 2002 from 2001 due
to state tax changes in connection with the Ohio electric industry
restructuring.
Net Interest Charges
Net interest charges continued to trend lower decreasing by
$3.8 million in 2002 and $5.9 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 $264.1 million and
$51.8 million, respectively, and will result in annualized savings of $23.2
million.
5
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 total debt by approximately $163
million. Our common stockholder's equity as a percentage of capitalization
increased to 50% as of December 31, 2002 from 27% at the end of 1997. Over the
last five years, we have reduced the average cost of outstanding debt from 9.13%
in 1997 to 6.61% in 2002.
Changes in Cash Position
As of December 31, 2002, we had $20.7 million of cash and cash
equivalents, which was 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 $156 million in 2002 and $190 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) $ 142 $ 236
Working capital and other 14 (46)
-----------------------------------------------------------
Total $ 156 $ 190
===========================================================
(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 $29
million primarily reflects the redemptions of debt and preferred stock shown
below. 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 $ 20
REDEMPTIONS
Unsecured Notes 135
Secured Notes 44
Preferred Stock 85
Other, principally redemption premiums 2
---------------------------------------------------------------
266
Short-term Borrowings, Net 132
---------------------------------------------------------------
In 2001, net cash used for financing activities totaled $97.8
million, primarily due to redemptions of $42 million of long-term debt notes and
dividend payments of $30.8 million.
We had about $22.6 million of cash and temporary investments
and $149.7 million of short-term indebtedness as of December 31, 2002. Under our
first mortgage indenture, as of December 31, 2002, we had the capability to
issue $144 million of additional first mortgage bonds on the basis of property
additions and retired bonds. Based on our earnings in 2002 under the earnings
coverage test contained in our charter, we could not issue additional preferred
stock (assuming no additional debt was issued). At the end of 2002, our common
equity as a percentage of capitalization, stood at 50% compared to 45% 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 and a $100
million equity contribution from FirstEnergy.
6
Cash Flows From Investing Activities
Net cash used in investing activities totaled $106 million in
2002. The net cash used for investing resulted from property additions.
Expenditures for property additions primarily include expenditures supporting
our distribution of electricity. In 2001, net cash used in investing activities
totaled $93 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. Available borrowing capacity under short-term credit
facilities will be used to manage working capital requirements. 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................... $ 730 $116 $215 $ 30 $ 369
Short-term borrowings............ 150 150 -- -- --
Preferred stock (1).............. -- -- -- -- --
Capital leases (2)............... -- -- -- -- --
Operating leases (2)............. 1,067 75 153 158 681
Purchases (3).................... 269 30 75 64 100
-------------------------------------------------------------------------------------------------------------
Total....................... $ 2,216 $371 $443 $ 252 $ 1,150
-------------------------------------------------------------------------------------------------------------
(1) Subject to mandatory redemption.
(2) Operating lease payments are net of capital trust receipts of $363.3 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 $169 million (excluding nuclear fuel) of which $54 million applies to
2003. Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $34 million, of which about $12 million relates to
2003. During the same periods, our nuclear fuel investments are expected to be
reduced by approximately $40 million and $19 million, respectively, as the
nuclear fuel is consumed.
On February 22, 2002, Moody's Investor 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 its decision
on the mechanism for sharing merger savings and reversed the PPUC's decisions
regarding rate relief and accounting deferrals rendered in connection with its
approval of the GPU merger. 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 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 from FirstEnergy (see Note 6 - Sale of
Generating Assets) 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, its ratings
would not be affected. S&P found FirstEnergy's 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 FirstEnergy's
progress on various initiatives. On January 21, 2003, S&P indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa
(FirstEnergy's Argentina Operations), which were higher than anticipated in the
third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear
plant "...without significant delay beyond April 2003..." as key to maintaining
its current debt ratings. S&P also identified other issues it would continue to
monitor including: FirstEnergy's deleveraging efforts, free cash generated
during 2003, the Jersey Central Power & Light Company rate case, successful
hedging of its short power position, and continued capture of projected merger
savings. While FirstEnergy anticipates 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 its
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 FirstEnergy reduces debt could put additional pressure on
the Company's credit ratings.
7
Other Obligations
Obligations not included on our Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving the Bruce
Mansfield Plant and Beaver Valley Unit 2, which are reflected in the operating
lease payments above (see Note 2 - Leases). The present value as of December 31,
2002, of these sale and leaseback operating lease commitments, net of trust
investments, total $621 million. We sell substantially all of our retail
customer receivables, which provided $52 million of off balance sheet financing
as of December 31, 2002.
INTEREST RATE RISK
Our exposure to fluctuations in market interest rates is
reduced since a significant portion of our debt has fixed interest rates, as
noted in the table below. We are subject to the inherent risks related to
refinancing maturing debt by issuing new debt securities. As discussed in Note
2, our investment in the Shippingport Capital Trust effectively reduces future
lease obligations, also reducing interest rate risk. Changes in the market value
of our nuclear decommissioning trust funds 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 customers the difference between the investments
held in trust and their decommissioning obligations. Thus, in absence of
disallowed costs, there should be no earnings effect from fluctuations in their
decommissioning trust balances. 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
and debt obligations.
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................. $ 20 $ 9 $134 $ 12 $ 9 $ 290 $ 474 $ 515
Average interest rate..... 7.7% 7.7% 7.8% 7.7% 7.7% 6.8% 7.2%
-------------------------------------------------------------------------------------------------------------------
Liabilities
-------------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $116 $215 $ 30 $ 160 $ 521 $ 562
Average interest rate .... 7.7% 7.8% 7.1% 7.8% 7.7%
Variable rate................ $ 209 $ 209 $ 210
Average interest rate..... 3.0% 3.0%
Short-term Borrowings........ $150 $ 150 $ 150
Average interest rate..... 1.8% 1.8%
-------------------------------------------------------------------------------------------------------------------
EQUITY PRICE RISK
Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $90
million and $90 million as of December 31, 2002 and 2001, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$9 million reduction in fair value as of December 31, 2002 (see Note 1K -
Supplemental Cash Flows Information)
OUTLOOK
Our industry continues to transition to a more competitive
environment. In 2001, all our customers could select alternative energy
suppliers. We continue to deliver power to residential homes and businesses
through our existing distribution systems, which remain regulated. Customer
rates have been restructured into separate components to support customer
choice. We have a continuing responsibility to provide power to our 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 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,
8
and the customer receives a generation charge from the alternative supplier. We
have continuing responsibility to provide energy to our franchise customers as
the PLR through December 31, 2005. Regulatory assets are costs which have been
authorized by the Public Utilities Commission of Ohio (PUCO) 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 are $578.2 million as of December 31,
2002 and $642.2 million as of December 31, 2001.
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 $80 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, TE 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 160 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 our load. In 2003, the total peak load forecasted for customers
electing to stay with us, including the 160 MW of low cost supply and the load
served by our affiliate is 2,020 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).
The actual costs (capital and expense) associated with the
extended Davis-Besse outage (TE share - 48.62%) 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
---------------------------------------------------------------------------------
9
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. Having restored service to its customers, FirstEnergy is now in
the process of 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 a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved,
are often unsubstantiated and subject to dispute. Federal law provides that all
PRPs for a particular site be held liable on a joint and several basis. We have
accrued a liability of $0.2 million as of December 31, 2002, based on estimates
of the total costs of cleanup, the proportionate responsibility of other PRPs
for such costs and the financial ability of other PRPs to pay. We believe that
waste disposal costs will not have a material adverse effect on our financial
condition, cash flows, or results of operations.
The effects of compliance on the Company 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 generally accepted in the United States. Application
of these principles often requires a high degree of judgment, estimates and
assumptions that affect our financial results. All of our assets are subject to
their own specific risks and uncertainties and are continually reviewed for
impairment. Assets related to the application of the policies discussed below
are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we
are permitted to charge our customers based on our costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory
10
framework in Ohio, significant amounts of regulatory assets have been recorded
-- $578.2 million as of December 31, 2002. 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 kilowatt-hour 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 kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour 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. 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 obligation. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, we reduced the assumed
discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75%
used in 2000.
Our assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by our pension trusts. The market values of our pension assets have been
affected by sharp declines in the equity markets since mid-2000. In 2002, 2001
and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our
pension costs in 2002 were computed assuming a 10.25% rate of return on plan
assets. As of December 31, 2002 the assumed return on plan assets was reduced to
9.00% based upon our projection of future returns and pension trust investment
allocation of approximately 60% large cap equities, 10% small cap equities and
30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, we will not be required to fund 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:
11
INCREASE IN COSTS FROM ADVERSE CHANGES IN KEY ASSUMPTIONS
ASSUMPTION ADVERSE CHANGE PENSION OPEB TOTAL
----------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Discount rate Decrease by 0.25% $0.2 $0.2 $0.4
Long-term return on assets Decrease by 0.25% 0.1 -- 0.1
Health care trend rate Increase by 1% na 0.5 0.5
INCREASE IN MINIMUM PENSION LIABILITY
Discount rate Decrease by 0.25% 4.4 na 4.4
----------------------------------------------------------------------------------------------------------
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 $18.7 million and established a minimum liability of $25.0
million, recording an intangible asset of $7.6 million and reducing OCI by $21.1
million (recording a related deferred tax benefit of $15.0 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 $3 million and $1 million, respectively - a total of $4
million in 2003 as compared to 2002.
Ohio Transition Cost Amortization
In developing TE'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 TE'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 TE. In
computing the transition cost amortization, TE 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).
Goodwill
The regulations in the jurisdictions in which TE operates do
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 $504.5 million 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
12
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 $123.2
million were recorded as part of the carrying amount of the related long-lived
asset, offset by accumulated depreciation of $15.0 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 $172 million. As of December 31, 2002, the
Company had recorded decommissioning liabilities of $179.6 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 $115.2
million increase to income ($67.3 million net of tax). 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 $115.2 million increase to income ($67.3
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.
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 (TE's third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
TE 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. TE currently consolidates the
majority of these entities and believes it will continue to consolidate
following the adoption of FIN 46. One of these entities TE 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.
13
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 (FirstEnergy's third quarter of 2003) for all other financial instruments.
TE did not enter into or modify any financial instruments
within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150,
effective July 1, 2003, TE expects to classify as debt the preferred stock of
consolidated subsidiaries subject to mandatory redemptions with a carrying value
of approximately $19 million as of June 30, 2003. Subsidiary preferred dividends
on FirstEnergy's Consolidated Statements of Income are currently included in net
interest charges. Therefore, the application of SFAS 150 will not require the
reclassification of such preferred dividends to net interest charges.
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. FirstEnergy 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.
FirstEnergy 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 TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
----------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
OPERATING REVENUES (a) (NOTE 1).................................. $996,045 $1,086,503 $954,947
-------- ---------- --------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1)............................. 366,932 457,444 159,039
Nuclear operating costs (Note 1).............................. 252,608 155,832 172,363
Other operating costs (Note 1)................................ 141,997 134,744 157,686
-------- ---------- --------
Total operation and maintenance expenses.................... 761,537 748,020 489,088
Provision for depreciation and amortization................... 162,082 176,796 106,514
General taxes................................................. 53,223 57,810 90,837
Income taxes.................................................. (17,496) 17,913 74,183
-------- ---------- --------
Total operating expenses and taxes.......................... 959,346 1,000,539 760,622
-------- ---------- --------
OPERATING INCOME................................................. 36,699 85,964 194,325
OTHER INCOME (NOTE 1)............................................ 13,329 15,652 8,669
-------- ---------- --------
INCOME BEFORE NET INTEREST CHARGES............................... 50,028 101,616 202,994
-------- ---------- --------
NET INTEREST CHARGES:
Interest on long-term debt.................................... 58,120 66,463 72,892
Allowance for borrowed funds used during
construction................................................ (2,502) (3,848) (6,523)
Other interest expense (credit)............................... (448) (3,690) (1,519)
-------- ---------- --------
Net interest charges........................................ 55,170 58,925 64,850
-------- ---------- --------
NET INCOME (LOSS)................................................ (5,142) 42,691 138,144
PREFERRED STOCK DIVIDEND
REQUIREMENTS.................................................. 10,756 16,135 16,247
-------- ---------- --------
EARNINGS (LOSS) ON COMMON STOCK.................................. $(15,898) $ 26,556 $121,897
======== ========== ========
*See Note 1(M).
(a) Includes electric sales to associated companies of $232.2 million, $277.9
million and $142.3 million in 2002, 2001 and 2000, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
15
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS (RESTATED*)
AS OF DECEMBER 31, 2002 2001
---------------------------------------------------------------------------------------------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service...................................................... $ 1,600,860 $ 1,578,943
Less-Accumulated provision for depreciation..................... 706,772 645,865
----------- -----------
894,088 933,078
----------- -----------
Construction work in progress-
Electric plant............................................... 104,091 40,220
Nuclear fuel................................................. 33,650 19,854
----------- -----------
137,741 60,074
----------- -----------
1,031,829 993,152
----------- -----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2)............................. 240,963 262,131
Nuclear plant decommissioning trusts............................ 174,514 156,084
Long-term notes receivable from associated companies............ 162,159 162,347
Other........................................................... 2,236 4,248
----------- -----------
579,872 584,810
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents....................................... 20,688 302
Receivables-
Customers.................................................... 4,711 5,922
Associated companies......................................... 55,245 64,667
Other........................................................ 6,778 1,309
Notes receivable from associated companies...................... 1,957 7,607
Materials and supplies, at average cost-
Owned........................................................ 13,631 13,996
Under consignment............................................ 22,997 17,050
Prepayments and other........................................... 3,455 14,580
----------- -----------
129,462 125,433
----------- -----------
DEFERRED CHARGES:
Regulatory assets............................................... 578,243 642,246
Goodwill........................................................ 504,522 504,522
Property taxes.................................................. 23,429 23,836
Other........................................................... 14,257 1,909
----------- -----------
1,120,451 1,172,513
----------- -----------
$ 2,861,614 $ 2,875,908
=========== ===========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity..................................... $ 681,195 $ 629,805
Preferred stock not subject to mandatory redemption............. 126,000 126,000
Long-term debt.................................................. 557,265 646,174
----------- -----------
1,364,460 1,401,979
----------- -----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock............ 189,355 347,593
Accounts payable-
Associated companies......................................... 171,862 53,960
Other........................................................ 9,338 29,818
Notes payable to associated companies........................... 149,653 17,208
Accrued taxes.................................................. 34,676 35,355
Accrued interest................................................ 16,377 19,918
Deferred lease costs............................................ 24,600 24,600
Other........................................................... 57,462 41,622
----------- -----------
653,323 570,074
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes............................... 158,279 170,364
Accumulated deferred investment tax credits..................... 29,255 31,266
Nuclear plant decommissioning costs............................. 179,587 151,226
Pensions and other postretirement benefits...................... 82,553 120,561
Deferred lease costs............................................ 317,200 341,800
Other........................................................... 76,957 88,638
----------- -----------
843,831 903,855
----------- -----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5).................................................
----------- -----------
$ 2,861,614 $ 2,875,908
=========== ===========
*See Note 1(M).
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
16
THE TOLEDO EDISON 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, $5 par value, authorized 60,000,000 shares
39,133,887 shares outstanding............................................... $ 195,670 $ 195,670
Other paid-in capital.......................................................... 428,559 328,559
Accumulated other comprehensive loss (Note 3E)................................. (20,012) 7,100
Retained earnings (Note 3A).................................................... 76,978 98,476
---------- ----------
Total common stockholder's equity........................................... 681,195 629,805
========== ==========
NUMBER OF SHARES OPTIONAL
OUTSTANDING REDEMPTION PRICE
--------------- --------------------
2002 2001 PER SHARE AGGREGATE 2002 2001
---- ---- --------- --------- ---- ----
PREFERRED STOCK (NOTE 3C):
Cumulative, $100 par value-
Authorized 3,000,000 shares
Not Subject to Mandatory Redemption:
$ 4.25........................... 160,000 160,000 $104.63 $ 16,740 16,000 16,000
$ 4.56........................... 50,000 50,000 101.00 5,050 5,000 5,000
$ 4.25........................... 100,000 100,000 102.00 10,200 10,000 10,000
$ 8.32........................... -- 100,000 -- -- -- 10,000
$ 7.76........................... -- 150,000 -- -- -- 15,000
$ 7.80........................... -- 150,000 -- -- -- 15,000
$ 10.00........................... -- 190,000 -- -- -- 19,000
------- ------- --------- ------- -------
310,000 900,000 31,990 31,000 90,000
Redemption Within One Year -- (59,000)
------- ------- --------- ------- -------
310,000 900,000 31,990 31,000 31,000
------- ------- --------- ------- -------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$2.21............................. -- 1,000,000 -- -- -- 25,000
$2.365............................ 1,400,000 1,400,000 27.75 38,850 35,000 35,000
Adjustable Series A............... 1,200,000 1,200,000 25.00 30,000 30,000 30,000
Adjustable Series B............... 1,200,000 1,200,000 25.00 30,000 30,000 30,000
--------- --------- --------- ------- -------
3,800,000 4,800,000 98,850 95,000 120,000
Redemption Within One Year........... -- (25,000)
--------- --------- --------- ------- -------
3,800,000 4,800,000 98,850 95,000 95,000
--------- --------- --------- ------- -------
Total Not Subject to Mandatory
Redemption.................. 4,110,000 5,700,000 $ 130,840 126,000 126,000
========= ========= ========= ------- -------
2002 2001
LONG-TERM DEBT (NOTE 3D):
First mortgage bonds:
8.000% due 2003........................................................... 33,725 34,125
7.875% due 2004........................................................... 145,000 145,000
---------- ----------
Total first mortgage bonds............................................... 178,725 179,125
---------- ----------
Unsecured notes and debentures:
8.700% due 2002........................................................... -- 135,000
10.000% due 2003-2010...................................................... 910 940
* 4.850% due 2030........................................................... 34,850 34,850
* 4.000% due 2033........................................................... 5,700 5,700
* 4.500% due 2033........................................................... 31,600 31,600
* 5.580% due 2033........................................................... 18,800 18,800
---------- ----------
Total unsecured notes and debentures..................................... 91,860 226,890
---------- ----------
*See Note 1(M).
17
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*) (CONT'D)
AS OF DECEMBER 31, 2002 2001
----------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
LONG-TERM DEBT (CONT'D):
Secured notes:
8.180% due 2002............................................................. -- 17,000
8.620% due 2002............................................................. -- 7,000
8.650% due 2002............................................................. -- 5,000
7.760% due 2003............................................................. 5,000 5,000
7.780% due 2003............................................................. 1,000 1,000
7.820% due 2003............................................................. 38,400 38,400
7.850% due 2003............................................................. 15,000 15,000
7.910% due 2003............................................................. 3,000 3,000
7.670% due 2004............................................................. 70,000 70,000
7.130% due 2007............................................................. 30,000 30,000
7.625% due 2020............................................................. 45,000 45,000
7.750% due 2020............................................................. 54,000 54,000
9.220% due 2021............................................................. 15,000 15,000
10.000% due 2021............................................................. -- 15,000
6.875% due 2023............................................................. 20,200 20,200
8.000% due 2023............................................................. 30,500 30,500
** 1.700% due 2024............................................................. 67,300 67,300
6.100% due 2027............................................................. 10,100 10,100
5.375% due 2028............................................................. 3,751 3,751
** 1.400% due 2033............................................................. 30,900 30,900
** 1.350% due 2033............................................................. 20,200 --
---------- ----------
Total secured notes...................................................... 459,351 483,151
---------- ----------
Capital lease obligations (Note 2)................................................ -- 263
---------- ----------
Net unamortized premium on debt................................................... 16,684 20,338
---------- ----------
Long-term debt due within one year................................................ (189,355) (263,593)
---------- ----------
Total long-term debt..................................................... 557,265 646,174
---------- ----------
TOTAL CAPITALIZATION.............................................................. $1,364,460 $1,401,979
========== ==========
* 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 TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
ACCUMULATED
OTHER OTHER
COMPREHENSIVE NUMBER PAR PAID-IN COMPREHENSIVE RETAINED
INCOME (LOSS) OF SHARES VALUE CAPITAL INCOME (LOSS) EARNINGS
--------------- ---------- -------- -------- ------------- ---------------
RESTATED RESTATED
(SEE NOTE 1(M)) (SEE NOTE 1(M))
(DOLLARS IN THOUSANDS)
Balance, January 1, 2000............................. 39,133,887 $195,670 $328,559 $ -- $ 27,475
Cumulative effect for restatement (see Note 1 (m) 4,349
------------------------------------------------------------------------------------------------------------------------------------
Restated balance at January 1, 2000.................. 31,824
Net income........................................ $ 138,144 138,144
=========
Cash dividends on preferred stock................. (16,250)
Cash dividends on common stock.................... (67,100)
------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000........................... 39,133,887 195,670 328,559 86,618
Net income........................................ $ 42,691 42,691
Unrealized gain on investments, net of
$4,800 of income taxes......................... 7,100 7,100
---------
Comprehensive income.............................. $ 49,791
=========
Cash dividends on preferred stock................. (16,133)
Cash dividends on common stock.................... (14,700)
------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001........................... 39,133,887 195,670 328,559 7,100 98,476
Net income (loss)................................. $ ( 5,142) (5,142)
Unrealized loss on investments, net of
$(4,034)of income taxes........................ (5,997) (5,997)
Minimum liability for unfunded retirement
benefits, net of $(15,042,000) of income
taxes.......................................... (21,115) (21,115)
---------
Comprehensive loss................................ $ (32,254)
Equity contribution from parent................... 100,000
Cash dividends on preferred stock................. (9,457)
Cash dividends on common stock.................... (5,600)
Preferred stock redemption premiums............... (1,299)
------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002........................... 39,133,887 $195,670 $428,559 $(20,012) $ 76,978
====================================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
NOT SUBJECT TO
MANDATORY REDEMPTION
--------------------
NUMBER
OF SHARES VALUE
--------- ---------
(DOLLARS IN THOUSANDS)
Balance, January 1, 2000.................. 5,700,000 $ 210,000
--------------------------------------------------------------------
Balance, December 31, 2000................ 5,700,000 210,000
--------------------------------------------------------------------
Balance, December 31, 2001................ 5,700,000 210,000
--------------------------------------------------------------------
Redemptions
$ 8.32 . Series...................... (100,000) (10,000)
$ 7.76 . Series...................... (150,000) (15,000)
$ 7.80 . Series...................... (150,000) (15,000)
$10.00 Series...................... (190,000) (19,000)
$ 2.21 . Series...................... (1,000,000) (25,000)
--------------------------------------------------------------------
Balance, December 31, 2002................ 4,110,000 $ 126,000
====================================================================
* See Note 1(M) to the Consolidated Financial Statements.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
19
THE TOLEDO EDISON 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 (Loss).......................................... $ (5,142) $ 42,691 $ 138,144
Adjustments to reconcile net income (loss) to net
cash from operating activities:
Provision for depreciation and amortization.......... 162,082 176,796 106,514
Nuclear fuel and lease amortization.................. 11,866 22,222 23,881
Deferred income taxes, net........................... (24,821) (1,383) 22,165
Investment tax credits, net.......................... (1,851) (3,832) (1,827)
Receivables.......................................... 5,164 (1,437) (6,671)
Materials and supplies............................... (5,582) 8,336 4,093
Accounts payable..................................... 40,801 22,144 13,997
Accrued taxes........................................ (4,881) (17,671) (223)
Accrued interest..................................... (3,541) (28) (2,015)
Prepayments and other................................ 11,125 12,571 (1,220)
Deferred lease costs................................. (24,600) (24,600) (5,700)
Other................................................ (5,082) (45,953) (33,322)
---------- --------- ---------
Net cash used for operating activities............ 155,538 189,856 257,816
---------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 19,580 -- 96,405
Short-term borrowings, net........................... 132,445 -- 8,060
Equity contributions from parent..................... 100,000 -- --
Redemptions and Repayments-
Preferred stock...................................... (85,299) -- --
Long-term debt....................................... (180,368) (42,265) (200,633)
Short-term borrowings, net........................... -- (24,728) --
Dividend Payments-
Common stock......................................... (5,600) (14,700) (67,100)
Preferred stock...................................... (10,057) (16,135) (16,247)
---------- --------- ---------
Net cash used for financing activities............ (29,299) (97,828) (179,515)
---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions......................................... (105,510) (112,451) (92,860)
Loans to associated companies.............................. -- (123,438) (63,838)
Loan payments from associated companies.................... 5,838 25,185 --
Capital trust investments.................................. 21,168 17,705 15,618
Sale of assets to associated companies..................... -- 123,438 81,014
Other...................................................... (27,349) (23,550) (17,162)
---------- --------- ---------
Net cash used for investing activities............ (105,853) (93,111) (77,228)
---------- --------- ---------
Net increase (decrease) in cash and cash equivalents....... 20,386 (1,083) 1,073
Cash and cash equivalents at beginning of year............. 302 1,385 312
---------- --------- ---------
Cash and cash equivalents at end of year................... $ 20,688 $ 302 $ 1,385
========== ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)................... $ 61,498 $ 63,159 $ 71,009
========== ========= =========
Income taxes............................................ $ 3,561 $ 33,210 $ 65,553
========== ========= =========
*See Note 1(M).
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
20
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
--------------------------------------------------------------------------------------------
(IN THOUSANDS)
GENERAL TAXES:
Real and personal property ............................. $ 22,737 $ 23,624 $ 46,302
Ohio kilowatt-hour excise** ............................ 28,046 19,576 --
State gross receipts** ................................. -- 12,789 36,813
Social security and unemployment ....................... 1,684 1,128 7,220
Other .................................................. 756 693 502
--------- --------- ---------
Total general taxes ........................... $ 53,223 $ 57,810 $ 90,837
========= ========= =========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal ............................................. $ 12,845 $ 22,244 $ 56,631
State ............................................... 3,983 4,840 1,811
--------- --------- ---------
16,828 27,084 58,442
--------- --------- ---------
Deferred, net-
Federal ............................................. (19,091) 4,725 22,216
State ............................................... (5,570) (1,539) (51)
--------- --------- ---------
(24,661) 3,186 22,165
--------- --------- ---------
Investment tax credit amortization ..................... (2,011) (3,908) (1,827)
--------- --------- ---------
Total provision for income taxes .............. $ (9,844) $ 26,362 $ 78,780
========= ========= =========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income ....................................... $ (17,496) $ 17,913 $ 74,183
Other income ........................................... 7,652 8,449 4,597
--------- --------- ---------
Total provision for income taxes .............. $ (9,844) $ 26,362 $ 78,780
========= ========= =========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes .......... $ (14,986) $ 69,053 $ 216,924
========= ========= =========
Federal income tax expense at statutory rate ........... $ (5,245) $ 24,169 $ 75,923
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit (1,031) 2,146 1,144
Amortization of investment tax credits .............. (2,011) (3,908) (1,827)
Amortization of tax regulatory assets ............... (2,362) (2,563) (1,737)
Amortization of goodwill ............................ -- 4,911 4,894
Other, net .......................................... 805 1,607 383
--------- --------- ---------
Total provision for income taxes .............. $ (9,844) $ 26,362 $ 78,780
========= ========= =========
ACCUMULATED DEFERRED INCOME TAXES
AT DECEMBER 31:
Property basis differences ............................. $ 177,262 $ 171,976 $ 163,537
Competitive transition charge .......................... 196,812 239,088 192,444
Unamortized investment tax credits ..................... (11,414) (12,184) (16,689)
Unused alternative minimum tax credits ................. -- -- (5,100)
Deferred gain for asset sale to affiliated company ..... 14,186 16,305 15,330
Other comprehensive income ............................. (14,276) 4,800 --
Above market leases .................................... (140,399) (150,634) (160,868)
Retirement benefits .................................... (9,768) (35,126) (28,656)
Other .................................................. (54,124) (63,861) (2,334)
--------- --------- ---------
Net deferred income tax liability ................... $ 158,279 $ 170,364 $ 157,664
========= ========= =========
* See Note 1(M).
** Collected from customers through regulated rates and included in revenue on
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 Toledo Edison Company
(Company) and its 90% owned subsidiary, The Toledo Edison Capital Corporation
(TECC). The subsidiary was formed in 1997 to make equity investments in a
business trust in connection with the financing transactions related to the
Bruce Mansfield Plant sale and leaseback (see Note 2). The Cleveland Electric
Illuminating Company (CEI), an affiliate, has a 10% interest in TECC. 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, CEI, Ohio Edison Company (OE),
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 northwestern 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 CEI sell substantially all of their retail customers'
receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of
CEI. 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, FirstEnergy
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 $1.3 million in 2002.
Expenses associated with the factoring discount related to the sale of
receivables were $4.7 million in 2002.
22
(C) REGULATORY PLAN-
In July 1999, Ohio's electric utility restructuring legislation, which
allowed Ohio electric customers to select their generation suppliers beginning
January 1, 2001, was signed into law. Among other things, the legislation
provided for a 5% reduction on the generation portion of residential customers'
bills and the opportunity to recover transition costs, including regulatory
assets, from January 1, 2001 through December 31, 2005 (market development
period). The period for the recovery of regulatory assets only can be extended
up to December 31, 2010. The PUCO was authorized to determine the level of
transition cost recovery, as well as the recovery period for the regulatory
assets portion of those costs, in considering each Ohio electric utility's
transition plan application.
In July 2000, the PUCO approved FirstEnergy's transition plan for the
Company, OE and CEI 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 $0.8
billion net of deferred income taxes and transition costs related to regulatory
assets as filed of $0.5 billion net of deferred income taxes, with recovery
through no later than mid-2007 for the Company, except where a longer period of
recovery is provided for in the settlement agreement. The generation-related
transition costs include $0.3 billion of impaired generating assets recognized
as regulatory assets as described further below, $1.0 billion, net of deferred
income taxes, of above-market operating lease costs (see Note 1(M)) and $0.3
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 160 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 $5 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 $80 million. The Company has 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 71 has been discontinued with respect to the
Company's generation operations. The SEC issued interpretive guidance regarding
asset impairment measurement that concluded 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 $53 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 $559 million 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 in
connection with the purchase accounting and impairment tests prepared in
connection with the transition plan), 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 3.9% in 2002, 3.5% in 2001 and
3.4% in 2000.
Annual depreciation expense includes approximately $28.5 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 $475 million in current dollars and (using a 4.0%
escalation rate) approximately $1.0 billion in future dollars. The estimated
obligation and
23
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 $4.8 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 (FASB) issued
SFAS 143, "Accounting for Asset Retirement Obligations". The new statement
provides accounting standards for retirement obligations associated with
tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143
requires that the fair value of a liability for an asset retirement obligation
be recorded in the period in which it is incurred. The associated asset
retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. However, rate-regulated entities may recognize a regulatory asset or
liability if the criteria for such treatment are met. Upon retirement, a gain or
loss would be recorded if the cost to settle the retirement obligation differs
from the carrying amount.
The Company has identified applicable legal obligations as defined
under the new standard, principally for nuclear power plant decommissioning.
Upon adoption of SFAS 143, asset retirement costs of $123 million were recorded
as part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $15 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 $172
million. As of December 31, 2002, the Company had recorded decommissioning
liabilities of $179.6 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 will be a $115 million increase
to income ($67 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. As described above under
"Regulatory Plan" the Company recovers transition costs that represent a
significant source of cash. The Company is unable to predict how completion of
transition cost recovery will affect future goodwill impairment analyses. Prior
to the adoption of SFAS 142, the Company amortized about $14 million of goodwill
annually. The goodwill balance as of December 31, 2002 and 2001 was $505
million.
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 (loss) ............................. $ (5,142) $ 42,691 $ 138,114
Add back goodwill amortization ......................... -- 14,032 13,984
-------- -------- ---------
Adjusted net income (loss) ............................. $ (5,142) $ 56,723 $ 152,098
======== ======== =========
(E) COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, together with CEI 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:
24
UTILITY ACCUMULATED CONSTRUCTION OWNERSHIP/
PLANT PROVISION FOR WORK IN LEASEHOLD
GENERATING UNITS IN SERVICE DEPRECIATION PROGRESS INTEREST
---------------------------------------------------------------------------------------------
(IN MILLIONS)
Bruce Mansfield
Units 2 and 3........................ $ 46.0 $ 16.9 $ 21.0 18.61%
Beaver Valley Unit 2.................... 3.2 0.2 8.8 19.91%
Davis-Besse............................. 222.6 48.9 54.4 48.62%
Perry................................... 338.7 59.9 3.6 19.91%
---------------------------------------------------------------------------------------------
Total................................ $ 610.5 $ 125.9 $ 87.8
=============================================================================================
The Bruce Mansfield Plant and Beaver Valley Unit 2 are being leased
through sale and leaseback transactions (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.
25
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 (Company -
$18.7 million) and established a minimum liability of $548.6 million (Company -
$25.0 million), recording an intangible asset of $78.5 million (Company - $7.6
million) and reducing OCI by $444.2 million (Company - $21.1 million) (recording
a related deferred tax asset of $312.8 million (Company - $15.0 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...... $ 18.7 $ 1.6 $ (56.2) $ (119.1)
================================================================================================
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%
26
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............ $ 0.7 $ (0.7) $ (12.7) $ 4.4 $ 3.5 $ 15.1
----------------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately
10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. An increase in the health care cost trend
rate assumption by one percentage point would increase the total service and
interest cost components by $20.7 million and the postretirement benefit
obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
(J) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily CEI, OE, Penn, ATSI,
FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The
Ohio transition plan, as discussed in the "Regulatory Plans" 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, CEI, 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 CEI. 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........... $128.2 $180.9 $ --
Generating units rent with FES.. 14.0 14.0 --
Electric sales to CEI........... 104.0 97.0 106.8
Ground lease with ATSI.......... 1.7 1.7 1.9
OPERATING EXPENSES:
Purchased power under PSA....... 319.0 388.0 --
Transmission expenses (including
ATSI rent)................... 22.5 17.0 9.4
FirstEnergy support services.... 26.2 23.8 36.0
OTHER INCOME:
Interest income from ATSI....... 3.0 3.0 1.0
Interest income from FES........ 9.7 9.7 --
-----------------------------------------------------------------
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.
27
The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased
capacity entitlement to CEI. Operating revenues for this transaction were $104.0
million, $97.0 million and $104.0 million in 2002, 2001 and 2000, respectively.
This sale is expected to continue through the end of the lease period. (See Note
2.)
(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. As of
December 31, 2002, cash and cash equivalents included $30 million used to redeem
long-term debt in January 2003. Noncash financing and investing activities
included capital lease transactions amounting to $1.0 million and $36.1 million
in 2001 and 2000, respectively. There were no capital lease transactions in
2002.
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 and investments other than cash and cash equivalents as
of December 31:
2002 2001
---------------------------------------------------------------------------------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
---------------------------------------------------------------------------------------------------
(IN MILLIONS)
Long-term debt....................................... $730 $772 $889 $937
Investments other than cash and cash equivalents:
Debt securities
- Maturity (5-10 years)........................... $123 $127 $123 $127
- Maturity (more than 10 years)................... 278 303 299 296
Equity securities................................. 2 2 2 2
All other......................................... 175 175 157 157
---------------------------------------------------------------------------------------------------
$578 $607 $581 $582
===================================================================================================
The fair value of long-term debt reflects 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 the Company, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "All other" in the
table above) consist of equity securities, government bonds and corporate bonds.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in OCI in accordance with SFAS 115. Realized gains (losses) are
recognized as additions (reductions) to trust asset balances. For the year 2002,
net realized losses were approximately $5.0 million and interest and dividend
income totaled approximately $5.9 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 will continue to be recovered from customers under the
Company's transition plan. Based on that plan, the Company continues to bill and
collect cost-based rates for its transmission and distribution services, which
will remain regulated; accordingly, it is appropriate that the Company continues
the application of SFAS 71 to those operations.
28
Net regulatory assets on the Consolidated Balance Sheets are comprised
of the following:
2002 2001
--------------------------------------------------------------------------
REVISED
(SEE NOTE 1(M))
--------------------------------------------------------------------------
(IN MILLIONS)
Regulatory transition costs...................... $582.1 $648.1
Loss on reacquired debt.......................... 3.0 3.2
Other............................................ (6.9) (9.1)
-------------------------------------------------------------------------
Total..................................... $578.2 $642.2
=========================================================================
(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.
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. TE 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
previously recorded regulatory assets recovered under the transition period
through the end of 2007.
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 TE, under the purchase accounting rules of APB 16. In
connection with the reassessment of the accounting for the transition plan, the
FirstEnergy 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 statements 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 TE 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 Company, Regulatory Plan in effect at the
time of the merger and subsequently under the transition plan.
The total above-market lease obligation of $111 million associated with
Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017
(approximately $5.7 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 $298 million associated with the Bruce
Mansfield Plant is being amortized through the end of 2016 (approximately $18.9
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 2007.
29
The Company has reflected the impact of the accounting for the above
market lease obligations for the period from the merger in 1997 through 1999 as
a cumulative effect adjustment of $4.3 million to retained earnings as of
January 1, 2000. The after-tax effect of these items in the years ended December
31, 2002, 2001 and 2000 was as follows:
TRANSITION REVERSAL
COST OF LEASE
INCOME STATEMENT EFFECTS AMORTIZATION OBLIGATIONS(1) TOTAL
------------------------ ------------ -------------- -----
INCREASE (DECREASE) (IN THOUSANDS)
Year ended December 31, 2002
Nuclear operating expenses $ -- $ (5,700) $ (5,700)
Other operating expenses -- (18,900) (18,900)
Provision for depreciation and amortization 28,400 40,200 68,600
Income taxes (12,559) (6,372) (18,931)
-------- -------- --------
Total expense $ 15,841 $ 9,228 $ 25,069
======== ======== ========
Net income effect $(15,841) $ (9,228) $(25,069)
======== ======== ========
Year ended December 31, 2001
Nuclear operating expenses $ -- $ (5,700) $ (5,700)
Other operating expenses -- (18,900) (18,900)
Provision for depreciation and amortization 13,600 33,000 46,600
Income taxes (5,619) (3,177) (8,796)
-------- -------- --------
Total expense $ 7,981 $ 5,223 $ 13,204
======== ======== ========
Net income effect $ (7,981) $ (5,223) $(13,204)
======== ======== ========
Year ended December 31, 2000
Nuclear operating expenses $ -- $ (5,700) $ (5,700)
Other operating expenses -- -- --
Provision for depreciation and amortization -- 1,600 1,600
Income taxes -- 2,371 2,371
-------- -------- --------
Total expense $ -- $ (1,729) $ (1,729)
======== ======== ========
Net income effect $ -- $ 1,729 $ 1,729
======== ======== ========
(1) The provision for depreciation and amortization in 2001 and 2000 includes
goodwill amortization of $1.6 million.
In addition, the impact of the above market lease obligations increased
the following balances in the consolidated balance sheet as of January 1, 2000:
(in thousands)
Goodwill $ 61,990
Regulatory assets 298,000
---------
Total assets $ 359,990
=========
Other current liabilities $ 24,600
Deferred income taxes (41,059)
Other deferred credits 372,100
---------
Total liabilities $ 355,641
=========
Retained earnings $ 4,349
=========
The net 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).
(IN MILLIONS)
--------------------------------
2003............ $ 114
2004............ 131
2005............ 151
2006............ 95
2007............ 68
----------------------------
30
Other Unrecorded Adjustments
This restatement for the years ended December 31, 2002, 2001 and 2000
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 income impact by year was $7.2 million in 2002, $(7.0) million
in 2001 and $(0.8) million in 2000.
The effects of all of the changes in this restatement on the previously
reported Consolidated Balance Sheet as of December 31, 2002 and 2001, and the
Consolidated Statements of Income and Consolidated Statements of Cash Flows for
the years ended December 31, 2002, 2001 and 2000 are as follows:
2002 2001 2000
---------------------------------------------------------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
---------------------------------------------------------------------------------
(IN THOUSANDS)
CONSOLIDATED STATEMENTS OF INCOME
OPERATING REVENUES: $ 987,645 $ 996,045 $1,094,903 $1,086,503 $ 954,947 $ 954,947
EXPENSES:
Fuel and purchased power 366,932 366,932 457,444 457,444 159,039 159,039
Nuclear operating costs 258,308 252,608 161,532 155,832 178,063 172,363
Other operating costs 163,267 141,997 151,244 134,744 156,286 157,686
---------- ---------- ---------- ---------- ---------- ----------
Total operation and maintenance expenses 788,507 761,537 770,220 748,020 493,388 489,088
Provision for depreciation and amortization 93,482 162,082 130,196 176,796 104,914 106,514
General taxes 53,223 53,223 57,810 57,810 90,837 90,837
Income taxes (2,745) (17,496) 31,193 17,913 72,394 74,183
---------- ---------- ---------- ---------- ---------- ----------
Total expenses 932,467 959,346 989,419 1,000,539 761,533 760,622
---------- ---------- ---------- ---------- ---------- ----------
OPERATING INCOME 55,178 36,699 105,484 85,964 193,414 194,325
OTHER INCOME 13,329 13,329 15,652 15,652 8,669 8,669
---------- ---------- ---------- ---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES 68,507 50,028 121,136 101,616 202,083 202,994
---------- ---------- ---------- ---------- ---------- ----------
NET INTEREST CHARGES 55,170 55,170 58,225 58,925 64,850 64,850
---------- ---------- ---------- ---------- ---------- ----------
NET INCOME (LOSS) 13,337 (5,142) 62,911 42,691 137,233 138,144
PREFERRED STOCK DIVIDEND REQUIREMENT 11,356 10,756 16,135 16,135 16,247 16,247
---------- ---------- ---------- ---------- ---------- ----------
EARNINGS (LOSS) ON COMMON STOCK $ 1,981 $ (15,898) $ 46,776 $ 26,556 $ 120,986 $ 121,897
========== ========== ========== ========== ========== ==========
2002 2001 2000
----------------------------------------------------------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
----------------------------------------------------------------------------------
(IN THOUSANDS)
CONSOLIDATED BALANCE SHEETS
ASSETS
CURRENT ASSETS $ 129,462 $ 129,462 $ 133,833 $ 125,433
PROPERTY, PLANT AND EQUIPMENT 1,031,829 1,031,829 993,152 993,152
INVESTMENTS 579,872 579,872 584,810 584,810
DEFERRED CHARGES:
Regulatory assets 392,643 578,243 388,846 642,246
Goodwill 445,732 504,522 445,732 504,522
Other 37,686 37,686 25,745 25,745
---------- ---------- ---------- ----------
876,061 1,120,451 860,323 1,172,513
---------- ---------- ---------- ----------
$2,617,224 $2,861,614 $2,572,118 $2,875,908
========== ========== ========== ==========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES $ 628,084 $ 653,323 $ 546,167 $ 570,074
CAPITALIZATION
Common stockholders' equity 712,931 681,195 637,665 629,805
Preferred stock not subject to mandatory
redemption 126,000 126,000 126,000 126,000
Long-term debt 557,265 557,265 646,174 646,174
---------- ---------- ---------- ----------
1,396,196 1,364,460 1,409,839 1,401,979
---------- ---------- ---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 223,087 158,279 213,145 170,364
Accumulated deferred investment tax credits 29,491 29,255 31,342 31,266
Nuclear plant decommissioning costs 180,856 179,587 162,426 151,226
Other 159,510 476,710 209,199 550,999
---------- ---------- ---------- ----------
592,944 843,831 616,112 903,855
---------- ---------- ---------- ----------
$2,617,224 $2,861,614 $2,572,118 $2,875,908
========== ========== ========== ==========
31
CONSOLIDATED STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 13,337 $ (5,142) $ 62,911 $ 42,691 $ 137,233 $ 138,144
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 93,482 162,082 130,196 176,796 104,914 106,514
Nuclear fuel and lease amortization 11,866 11,866 22,222 22,222 23,881 23,881
Deferred income taxes, net (5,868) (24,821) 11,897 (1,383) 20,376 22,165
Investment tax credits, net (1,851) (1,851) (3,832) (3,832) (1,827) (1,827)
Receivables 13,564 5,164 (9,837) (1,437) (6,671) (6,671)
Materials and supplies (5,582) (5,582) 8,336 8,336 4,093 4,093
Accounts payable 42,501 40,801 19,744 22,144 13,997 13,997
Deferred rents and sale/leaseback -- (24,600) -- (24,600) -- (5,700)
Other (5,911) (2,379) (51,781) (51,081) (38,180) (36,780)
--------- --------- --------- --------- --------- ---------
Net cash provided from operating activities $ 155,538 $ 155,538 $ 189,856 $ 189,856 $ 257,816 $ 257,816
========= ========= ========= ========= ========= =========
CASH FLOWS FROM FINANCING ACTIVITIES $ (29,299) $ (29,299) $ (97,828) $ (97,828) $(179,515) $(179,515)
========= ========= ========= ========= ========= =========
CASH FLOWS FROM INVESTING ACTIVITIES $(105,853) $(105,853) $ (93,111) $ (93,111) $ (77,228) $ (77,228)
========= ========= ========= ========= ========= =========
2. LEASES:
The Company leases certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.
The Company and CEI sold their ownership interests in Bruce Mansfield
Units 1, 2 and 3 and the Company 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 CEI entered into operating leases for lease terms of
approximately 30 years as co-lessees. During the terms of the leases, the
Company and CEI 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 CEI have the
right, at the end of the respective basic lease terms, to renew the leases. The
Company and CEI 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 CEI, the Company is also obligated for CEI's lease
payments. If CEI is unable to make its payments under the Bruce Mansfield Plant
lease, the Company would be obligated to make such payments. No such payments
have been made on behalf of CEI. (CEI's future minimum lease payments as of
December 31, 2002 were approximately $0.2 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............... $ 52.6 $ 55.7 $ 58.7
Other.......................... 58.6 52.4 46.2
Capital leases
Interest element............... -- 2.5 3.9
Other.......................... 0.3 14.1 24.1
---------------------------------------------------------------
Total rentals.................. $111.5 $124.7 $132.9
===============================================================
The future minimum lease payments as of December 31, 2002 are:
OPERATING LEASES
-----------------------------------
LEASE CAPITAL
PAYMENTS TRUST NET
--------------------------------------------------------------------------------
(IN MILLIONS)
2003.................................... $ 111.7 $ 36.6 $ 75.1
2004.................................... 97.9 24.6 73.3
2005.................................... 104.8 25.3 79.5
2006.................................... 107.8 26.0 81.8
2007.................................... 99.2 22.6 76.6
Years thereafter........................ 908.7 228.2 680.5
--------------------------------------------------------------------------------
Total minimum lease payments............ $1,430.1 $ 363.3 $1,066.8
======== ======= ========
32
The Company and CEI 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
($145 million for the Company and $575 million for CEI) 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 ($337.1 million for the Company and $569.4 million for
CEI) 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 obligations 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-
The Company has a provision in its mortgage that requires common stock
dividends to be paid out of its total balance of retained earnings.
(B) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
-------------------------------------------------------------------------
Restricted common shares granted......... 36,922 133,162 208,400
Weighted average market price............ $ 36.04 $ 35.68 $ 26.63
Weighted average vesting period (years).. 3.2 3.7 3.8
Dividends restricted..................... Yes * Yes
-------------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan
dividends are paid as unrestricted cash on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
33
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-
Preferred stock may be redeemed by the Company in whole, or in part,
with 30-90 days' notice.
The preferred dividend rates on the Company's Series A and Series B
shares fluctuate based on prevailing interest rates and market conditions. The
dividend rates for both issues averaged 7% in 2002.
The Company has five million authorized and unissued shares of $25 par
value preference stock.
(D) 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. There also exists cross-default provisions among financing arrangements
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................................. $189.4
2004................................. 268.7
2005................................. 31.6
2006................................. --
2007................................. 30.0
-------------------------------------------------
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 $73 million, $54 million and $32 million in 2003, 2004
and 2005, respectively, which represents the next date at which the 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 irrevocable bank letters of
34
credit of $68.0 million and a noncancelable municipal bond insurance policy of
$51.1 million to pay principal of, or interest on, the pollution control revenue
bonds. To the extent that drawings are made under the letters of credit or
policy, the Company is entitled to a credit against its obligation to repay
those bonds. The Company pays an annual fee of 1.00% of the amounts of the
letters of credit to the issuing bank and is obligated to reimburse the bank for
any drawings thereunder.
The Company and CEI 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 CEI are jointly and severally liable
for the letters of credit (see Note 2).
(E) 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 $21.1 million and unrealized gains of $1.1
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 $149.7 million
from its affiliates. The average interest rate on short-term borrowings
outstanding as of December 31, 2002 and 2001, were 1.8% and 3.6%, respectively.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$169 million for property additions and improvements from 2003-2007, of which
approximately $54 million is applicable to 2003. Investments for additional
nuclear fuel during the 2003-2007 period are estimated to be approximately $34
million, of which approximately $12 million applies to 2003. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $40 million and $19 million, respectively, as the nuclear fuel is
consumed.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a single
incident at a nuclear power plant to $9.5 billion. The amount is covered by a
combination of private insurance and an industry retrospective rating plan.
Based on its ownership and leasehold interests in Beaver Valley Unit 2, the
Davis Besse Station and the Perry Plant, the Company's maximum potential
assessment under the industry retrospective rating plan (assuming the other
affiliate co-owners contribute their proportionate shares of any assessments
under the retrospective rating plan) would be $77.9 million per incident but not
more than $8.8 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 $263.4 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 $14.6 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.
35
The Company is required to meet federally approved sulfur
dioxide (SO2) regulations. Violations of such regulations can result in shutdown
of the generating unit involved and/or civil or criminal penalties of up to
$31,500 for each day the unit is in violation. The Environmental Protection
Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that
allows for compliance based on a 30-day averaging period. The Company cannot
predict what action the EPA may take in the future with respect to the interim
enforcement policy.
The Company believes it is in compliance with the current SO2
and nitrogen oxides (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOx reductions are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional NOx
reductions from the Company's Ohio and Pennsylvania facilities. The EPA's NOx
Transport Rule imposes uniform reductions of NOx emissions (an approximate 85%
reduction in utility plant NOx emissions from projected 2007 emissions) across a
region of nineteen states and the District of Columbia, including Ohio and
Pennsylvania, based on a conclusion that such NOx emissions are contributing
significantly to ozone pollution in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets established by the EPA. Pennsylvania submitted a SIP that requires
compliance with the NOx budgets at the Company's Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Company's Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National
Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new
NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the
U.S. Court of Appeals found constitutional and other defects in the new NAAQS
rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules
regulating ultra-fine particulates but found defects in the new NAAQS rules for
ozone and decided that the EPA must revise those rules. The future cost of
compliance with these regulations may be substantial and will depend if and how
they are ultimately implemented by the states in which the Company operates
affected facilities.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of
1976, as amended, and the Toxic Substances Control Act of 1976, federal and
state hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000,
the EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The Company has been named as a "potentially responsible
party" (PRP) at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; 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 $0.2 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) OTHER LEGAL PROCEEDINGS-
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 648 MW Bay Shore Plant owned by the Company. On
36
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 $13 million ($8 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. We do not believe that
implementation of FIN 45 will be material but we will continue to evaluate
anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB
No. 51, "Consolidated Financial Statements". The new interpretation provides
guidance on consolidation of variable interest entities (VIEs), generally
defined as certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This Interpretation requires
an enterprise to disclose the nature of its involvement with a VIE if the
enterprise has a significant variable interest in the VIE and to consolidate a
VIE if the enterprise is the primary beneficiary. VIEs created after January 31,
2003 are immediately subject to the provisions of FIN 46. VIEs created before
February 1, 2003 are subject to this interpretation's provisions in the first
interim or annual reporting period beginning after June 15, 2003 (TE's third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
TE 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. TE currently consolidates the
majority of these entities and believes it will continue to consolidate
following the adoption of FIN 46. One of these entities TE 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 (TE'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
37
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.
FirstEnergy 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. TE is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
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 $ 244.1 $ 252.6 $ 250.3 $ 250.3 $ 269.9 $ 269.9 $ 223.3 $223.3
Operating Expenses and Taxes 234.5 241.9 216.2 222.7 244.8 251.7 236.9 243.1
Operating Income (Loss) 9.6 10.7 34.1 27.6 25.1 18.2 (13.6) (19.8)
---------------------------------------------------------------------------------------------------------------------------------
Other Income 4.4 4.3 3.7 3.7 4.0 4.0 1.1 1.2
Net Interest Charges 14.7 14.7 14.8 14.9 14.5 14.5 11.2 11.1
Net Income (Loss) $ (0.7) $ 0.3 $ 23.0 $ 16.4 $ 14.6 $ 7.7 $ (23.7) $(29.7)
---------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Applicable to
Common Stock $ (5.4) $ (4.4) $ 20.8 $ 14.3 $ 12.4 $ 5.5 $ (25.8) $(31.4)
=================================================================================================================================
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, EXCEPT PER SHARE AMOUNTS)
Operating Revenues $ 271.6 $ 271.6 $ 263.0 $ 263.0 $ 306.5 $ 306.5 $ 253.8 $245.4
Operating Expenses and Taxes 243.3 246.6 229.6 232.9 278.9 282.2 237.6 238.8
Operating Income 28.3 25.0 33.4 30.1 27.6 24.3 16.2 6.6
-------------------------------------------------------------------------------------------------------------------------------
Other Income 3.8 3.8 2.2 2.2 3.9 3.9 5.7 5.7
Net Interest Charges 15.9 15.9 12.6 12.6 15.1 15.1 14.6 15.3
Net Income (Loss) $ 16.2 $ 12.9 $ 23.0 $ 19.7 $ 16.4 $ 13.1 $ 7.3 $ (3.0)
-------------------------------------------------------------------------------------------------------------------------------
Earnings on common Stock $ 12.2 $ 8.9 $ 18.9 $ 15.6 $ 12.4 $ 9.1 $ 3.3 $ (7.0)
===============================================================================================================================
(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 rates. In addition, the other adjustments discussed in
Note 1(M) increased (decreased) net income for the quarterly periods as
follows: (in millions)
2002 2001
---- ----
March 31....................... 6.9 --
December 31.................... 0.3 (7.0)
38
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).
39
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
40
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).
41
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 - TOLEDO EDISON (TE)
EXHIBIT
NUMBER
3a -- Amended Articles of Incorporation of TE, as amended
effective October 2, 1992 (Exhibit 3a, 1992 Form 10-K, File
No. 1-3583).
3b -- Amended and Restated Code of Regulations, dated March 15,
2002. (2001 Form 10-K, Exhibit 3b)
(B)4b(1) -- Indenture, dated as of April 1, 1947, between TE and The
Chase National Bank of the City of New York (now The Chase
Manhattan Bank (National Association)) (Exhibit 2(b), File
No. 2-26908).
4b(2) -- September 1, 1948 (Exhibit 2(d), File No. 2-26908).
4b(3) -- April 1, 1949 (Exhibit 2(e), File No. 2-26908).
4b(4) -- December 1, 1950 (Exhibit 2(f), File No. 2-26908).
4b(5) -- March 1, 1954 (Exhibit 2(g), File No. 2-26908).
4b(6) -- February 1, 1956 (Exhibit 2(h), File No. 2-26908).
4b(7) -- May 1, 1958 (Exhibit 5(g), File No. 2-59794).
4b(8) -- August 1, 1967 (Exhibit 2(c), File No. 2-26908).
4b(9) -- November 1, 1970 (Exhibit 2(c), File No. 2-38569).
4b(10) -- August 1, 1972 (Exhibit 2(c), File No. 2-44873).
4b(11) -- November 1, 1973 (Exhibit 2(c), File No. 2-49428).
4b(12) -- July 1, 1974 (Exhibit 2(c), File No. 2-51429).
4b(13) -- October 1, 1975 (Exhibit 2(c), File No. 2-54627).
4b(14) -- June 1, 1976 (Exhibit 2(c), File No. 2-56396).
4b(15) -- October 1, 1978 (Exhibit 2(c), File No. 2-62568).
42
4b(16) -- September 1, 1979 (Exhibit 2(c), File No. 2-65350).
4b(17) -- September 1, 1980 (Exhibit 4(s), File No. 2-69190).
4b(18) -- October 1, 1980 (Exhibit 4(c), File No. 2-69190).
4b(19) -- April 1, 1981 (Exhibit 4(c), File No. 2-71580).
4b(20) -- November 1, 1981 (Exhibit 4(c), File No. 2-74485).
4b(21) -- June 1, 1982 (Exhibit 4(c), File No. 2-77763).
4b(22) -- September 1, 1982 (Exhibit 4(x), File No. 2-87323).
4b(23) -- April 1, 1983 (Exhibit 4(c), March 31, 1983, Form 10-Q, File
No. 1-3583).
4b(24) -- December 1, 1983 (Exhibit 4(x), 1983 Form 10-K, File No.
1-3583).
4b(25) -- April 1, 1984 (Exhibit 4(c), File No. 2-90059).
4b(26) -- October 15, 1984 (Exhibit 4(z), 1984 Form 10-K, File No.
1-3583).
4b(27) -- October 15, 1984 (Exhibit 4(aa), 1984 Form 10-K, File No.
1-3583).
4b(28) -- August 1, 1985 (Exhibit 4(dd), File No. 33-1689).
4b(29) -- August 1, 1985 (Exhibit 4(ee), File No. 33-1689).
4b(30) -- December 1, 1985 (Exhibit 4(c), File No. 33-1689).
4b(31) -- March 1, 1986 (Exhibit 4b(31), 1986 Form 10-K, File No.
1-3583).
4b(32) -- October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q,
File No. 1-3583).
4b(33) -- September 15, 1988 (Exhibit 4b(33), 1988 Form 10-K, File No.
1-3583).
4b(34) -- June 15, 1989 (Exhibit 4b(34), 1989 Form 10-K, File No.
1-3583).
4b(35) -- October 15, 1989 (Exhibit 4b(35), 1989 Form 10-K, File No.
1-3583).
4b(36) -- May 15, 1990 (Exhibit 4, June 30, 1990 Form 10-Q, File No.
1-3583).
4b(37) -- March 1, 1991 (Exhibit 4(b), June 30, 1991 Form 10-Q, File
No. 1-3583).
4b(38) -- May 1, 1992 (Exhibit 4(a)(3), File No. 33-48844).
4b(39) -- August 1, 1992 (Exhibit 4b(39), 1992 Form 10-K, File No.
1-3583).
4b(40) -- October 1, 1992 (Exhibit 4b(40), 1992 Form 10-K, File No.
1-3583).
4b(41) -- January 1, 1993 (Exhibit 4b(41), 1992 Form 10-K, File No.
1-3583).
4b(42) -- September 15, 1994 (Exhibit 4(b), September 30, 1994 Form
10-Q, File No. 1-3583).
4b(43) -- May 1, 1995 (Exhibit 4(d), September 30, 1995 Form 10-Q,
File No. 1-3583).
4b(44) -- June 1, 1995 (Exhibit 4(e), September 30, 1995 Form 10-Q,
File No. 1-3583).
4b(45) -- July 14, 1995 (Exhibit 4(f), September 30, 1995 Form 10-Q,
File No. 1-3583).
4b(46) -- July 15, 1995 (Exhibit 4(g), September 30, 1995 Form 10-Q,
File No. 1-3583).
4b(47) -- August 1, 1997 (Exhibit 4b(47), 1998 Form 10-K, File No.
1-3583).
4b(48) -- June 1, 1998 (Exhibit 4b (48), 1998 Form 10-K, File No.
1-3583).
4b(49) -- January 15, 2000 (Exhibit 4b(49), 1999 Form 10-K, File No.
1-3583).
4b(50) -- May 1, 2000 (Exhibit 4b(50), 2000 Form 10-K, File No.
1-3583).
4b(51) -- September 1, 2000
4b(52) -- October 1, 2002
* 12.4 -- Consolidated fixed charge ratios.
* 13.3 -- TE 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.)
21.3 -- 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 of 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.
43
REPORTS ON FORM 8-K
TE
TE 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.
44
REPORT OF INDEPENDENT AUDITORS ON
FINANCIAL STATEMENT SCHEDULES
To the Stockholders and Board of Directors of The Toledo Edison 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 Toledo Edison 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
45
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 TOLEDO EDISON COMPANY
-------------------------
Registrant
/s/ Harvey L. Wagner
------------------------------
Harvey L. Wagner
Vice President and Controller
Chief Accounting Officer
Date: September 24, 2003
46