EXHIBIT 13.3
THE TOLEDO EDISON COMPANY
2002 ANNUAL REPORT TO STOCKHOLDERS
The Toledo Edison Company (TE) is a wholly owned electric utility
operating subsidiary of FirstEnergy Corp. It engages in the generation,
distribution and sale of electric energy in an area of approximately 2,500
square miles in northwestern Ohio. It also engages in the sale, purchase and
interchange of electric energy with other electric companies. The area it serves
has a population of approximately 0.8 million.
CONTENTS PAGE
Selected Financial Data........................................... 1
Management's Discussion and Analysis.............................. 2-15
Consolidated Statements of Income................................. 16
Consolidated Balance Sheets....................................... 17
Consolidated Statements of Capitalization......................... 18-19
Consolidated Statements of Common Stockholder's Equity............ 20
Consolidated Statements of Preferred Stock........................ 20
Consolidated Statements of Cash Flows............................. 21
Consolidated Statements of Taxes.................................. 22
Notes to Consolidated Financial Statements........................ 23-40
Report of Independent Auditors.................................... 41
THE TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA (RESTATED*)
2002 2001 2000 1999 1998
---------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
GENERAL FINANCIAL INFORMATION:
Operating Revenues $ 996,045 $ 1,086,503 $ 954,947 $ 921,159 $ 957,037
=========== =========== =========== =========== ===========
Operating Income $ 36,699 $ 85,964 $ 194,325 $ 165,809 $ 182,298
=========== =========== =========== =========== ===========
Net Income (Loss) $ (5,142) $ 42,691 $ 138,144 $ 101,982 $ 108,619
=========== =========== =========== =========== ===========
Earnings (Loss) on Common Stock $ (15,898) $ 26,556 $ 121,897 $ 85,744 $ 95,009
=========== =========== =========== =========== ===========
Total Assets $ 2,861,614 $ 2,875,908 $ 3,010,657 $ 2,663,428 $ 3,130,355
=========== =========== =========== =========== ===========
CAPITALIZATION:
Common Stockholder's Equity $ 681,195 $ 629,805 $ 610,847 $ 557,853 $ 579,804
Preferred Stock Not Subject to Mandatory
Redemption 126,000 126,000 210,000 210,000 210,000
Long-Term Debt 557,265 646,174 944,193 981,029 1,083,666
----------- ----------- ----------- ----------- -----------
Total Capitalization $ 1,364,460 $ 1,401,979 $ 1,765,040 $ 1,748,882 $ 1,873,470
=========== =========== =========== =========== ===========
CAPITALIZATION RATIOS:
Common Stockholder's Equity 49.9% 44.6% 34.6% 31.8% 30.9%
Preferred Stock Not Subject to Mandatory
Redemption 9.2 9.0 11.9 12.0 11.2
Long-Term Debt 40.9 46.4 53.5 56.2 57.9
----- ----- ----- ----- -----
Total Capitalization 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
DISTRIBUTION KILOWATT-HOUR
DELIVERIES (MILLIONS):
Residential 2,427 2,258 2,183 2,127 2,252
Commercial 2,702 2,667 2,380 2,236 2,425
Industrial 5,280 5,397 5,595 5,449 5,317
Other 57 61 49 54 63
----- ----- ----- ----- -----
Total 10,466 10,383 10,207 9,866 10,057
====== ====== ====== ===== ======
CUSTOMERS SERVED:
Residential 272,474 270,589 269,071 266,900 265,237
Commercial 32,037 31,680 31,413 32,481 31,982
Industrial 1,883 1,898 1,917 1,937 1,954
Other 468 443 598 398 359
------- ------- ------- ------- -------
Total 306,862 304,610 302,999 301,716 299,532
======= ======= ======= ======= =======
NUMBER OF EMPLOYEES 508 507 539 977 997
* See Note 1(M) to the Consolidated Financial Statements.
1
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.
2
RESTATEMENTS
As further discussed in Note 1(M) to the Consolidated Financial
Statements, the Company is restating its consolidated financial statements for
the three years ended December 31, 2002. The revisions principally reflect a
change in the method of amortizing costs being recovered through the Ohio
transition plan and recognition of above-market values of certain leased
generation facilities.
Transition Cost Amortization
As discussed under Regulatory Plan in Note 1(C) to the Consolidated
Financial Statements, 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 $4.3
million to retained earnings as of January 1, 2000. The after-tax effect of
these items for the three years ended December 31, 2002 was as follows:
3
INCOME STATEMENT EFFECTS
INCREASE (DECREASE)
TRANSITION ABOVE MARKET
COST LEASES
AMORTIZATION OBLIGATIONS(1) TOTAL
------------ -------------- -----
(IN THOUSANDS)
Year ended December 31, 2002
Nuclear operating expenses$ -- $ (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........ $53
2004........ 71
2005........ 99
2006........ 76
2007........ 75
4
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, but revenues from electricity
throughput decreased by $11.1 million in 2002 from the prior year due to lower
unit prices. 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.
5
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 $18.0 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 $7.3 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.
6
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) $ 111 $ 236
Working capital and other 45 (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.
7
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.
8
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,
9
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:
10
COSTS OF DAVIS-BESSE EXTENDED OUTAGE 100%
--------------------------------------------------------------
(IN MILLIONS)
2002 - ACTUAL
Capital Expenditures:
Reactor head and restart....................... $ 63.3
Incremental Expenses (pre-tax):
Maintenance.................................... 115.0
Fuel and purchased power....................... 119.5
------
Total.......................................... $234.5
======
2003 - ESTIMATED
Primarily operating expenses (pre-tax):
Maintenance (including acceleration of programs) $ 50
Replacement power per month.................... $12-18
------
Power Outage
On August 14, 2003, eight states and southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. The cause of the outage has not been
determined. 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 (SO2)
and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 5 - Environmental
Matters). We continue to evaluate our compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in shutdown
of the generating unit involved and/or civil or criminal penalties of up to
$31,500 for each day a unit is in violation. The EPA has an interim enforcement
policy for SO2 regulations in Ohio that allows for compliance based on a 30-day
averaging period. We cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
We have been named as 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.
11
SIGNIFICANT ACCOUNTING POLICIES
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect our financial results. All of our assets are subject to
their own specific risks and uncertainties and are continually reviewed for
impairment. Assets related to the application of the policies discussed below
are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on our costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio, significant amounts of
regulatory assets have been recorded -- $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
12
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:
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
13
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 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).
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.
14
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
(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.
15
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.
16
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.
17
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
---- ---- --------- ---------
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
========== ========== ========== ---------- ----------
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).
18
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.
19
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
Unrealized gain on investments, net
of $00 of
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.
20
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.
21
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 (loss) 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 $ 157,674
========= ========= =========
* 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.
22
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.
23
(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
24
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:
25
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.
26
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%
27
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
28
customers and other factors; and specific departmental charge ratios. Management
believes that these allocation methods are reasonable.
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.
29
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.
30
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:
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 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
=========
31
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).
2003 $53
2004 71
2005 99
2006 76
2007 75
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
========== ========== ========== ========== ========== ==========
32
2002 2001 2000
--------------------------------------------------------------------------------
AS AS AS
PREVIOUSLY AS PREVIOUSLY 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 $ 681,195 $ 546,167 $ 570,074
CAPITALIZATION
Common stockholders' equity 712,931 682,995 637,665 629,805
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
========== ========== ========== ==========
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 $ 188,856 $ 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.
33
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
======== ======= ========
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.
34
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
- ------------------------------------------------------------------------------------------------
Restricted common shares granted................... 36,922 133,162 208,400
Weighted average market price ..................... $ 36.04 $ 35.68 $ 26.63
Weighted average vesting period (years)............ 3.2 3.7 3.8
Dividends restricted............................... Yes * Yes
- ------------------------------------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
Stock option activities under the FE Programs for the past three
years were as follows:
NUMBER OF WEIGHTED AVERAGE
STOCK OPTION ACTIVITIES OPTIONS EXERCISE PRICE
- ------------------------------------------------------------------------------------------------------
Balance, January 1, 2000............................. 2,153,369 $25.32
(159,755 options exercisable)........................ 24.87
Options granted................................... 3,011,584 23.24
Options exercised................................. 90,491 26.00
Options forfeited................................. 52,600 22.20
Balance, December 31, 2000.......................... 5,021,862 24.09
(473,314 options exercisable)........................ 24.11
Options granted................................... 4,240,273 28.11
Options exercised................................. 694,403 24.24
Options forfeited................................. 120,044 28.07
Balance, December 31, 2001........................... 8,447,688 26.04
(1,828,341 options exercisable)...................... 24.83
Options granted................................... 3,399,579 34.48
Options exercised................................. 1,018,852 23.56
Options forfeited................................. 392,929 28.19
Balance, December 31, 2002.......................... 10,435,486 28.95
(1,400,206 options exercisable)...................... 26.07
As of December 31, 2002, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected
in net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1G - "Stock-Based Compensation."
(C) PREFERRED AND PREFERENCE STOCK-
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.
35
(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
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 losses of
$(5,997).
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.
36
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on its ownership and leasehold interests in Beaver Valley Unit 2, the
Davis Besse Station and the Perry Plant, the Company's maximum potential
assessment under the industry retrospective rating plan (assuming the other
affiliate co-owners contribute their proportionate shares of any assessments
under the retrospective rating plan) would be $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.
The Company is required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Company cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Company believes it is in compliance with the current SO2 and
nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Company's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes
uniform reductions of NOx emissions (an approximate 85% reduction in utility
plant NOx emissions from projected 2007 emissions) across a region of nineteen
states and the District of Columbia, including Ohio and Pennsylvania, based on a
conclusion that such NOx emissions are contributing significantly to ozone
pollution in the eastern United States. State Implementation Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania submitted a SIP that requires compliance with the NOx budgets at
the Company's Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP
that requires compliance with the NOx budgets at the Company's Ohio facilities
by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient
Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals found constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating
ultra-fine particulates but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these regulations may be substantial and will depend if and how they are
ultimately implemented by the states in which the Company operates affected
facilities.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
37
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. 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 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
38
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 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.
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8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002(a) JUNE 30, 2002(a) SEPTEMBER 30, 2002(a) DECEMBER 31, 2002(a)
- --------------------------------------------------------------------------------------------------------------------------------
AS AS AS AS
PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
-------- -------- -------- -------- -------- -------- -------- --------
(IN MILLIONS)
Operating Revenues $ 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 $ 16.5 $ 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 AS AS AS
PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY 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)
40
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of The Toledo Edison Company:
In our opinion, the accompanying consolidated balance sheets and consolidated
statements of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of The Toledo Edison
Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of
December 31, 2002 and 2001, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2002 in
conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 1(D) to the consolidated financial statements, the Company
changed its method of accounting for goodwill in 2002.
As discussed in Note 1(M) to the consolidated financial statements, the Company
has restated its previously issued consolidated financial statements as of
December 31, 2002 and 2001 and for each of the three years in the period ended
December 31, 2002.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
41