_
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............................... 2-12
Consolidated Statements of Income.................................. 13
Consolidated Balance Sheets........................................ 14
Consolidated Statements of Capitalization.......................... 15-16
Consolidated Statements of Common Stockholder's Equity............. 17
Consolidated Statements of Preferred Stock......................... 17
Consolidated Statements of Cash Flows.............................. 18
Consolidated Statements of Taxes................................... 19
Notes to Consolidated Financial Statements......................... 20-33
Reports of Independent Accountants................................. 34-35
THE TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues...................... $ 987,645 $1,094,903 $ 954,947 $ 921,159 $ 957,037
========== ========== ========== ========== ==========
Operating Income........................ $ 55,178 $ 105,484 $ 193,414 $ 163,772 $ 180,261
========== ========== ========== ========== ==========
Net Income.............................. $ 13,337 $ 62,911 $ 137,233 $ 99,945 $ 106,582
========== ========== ========== ========== ==========
Earnings on Common Stock................ $ 1,981 $ 46,776 $ 120,986 $ 83,707 $ 92,972
========== ========== ========== ========== ==========
Total Assets............................ $2,617,224 $2,572,118 $2,652,267 $2,666,928 $2,768,765
========== ========== ========== ========== ==========
CAPITALIZATION:
Common Stockholder's Equity............. $ 712,931 $ 637,665 $ 605,587 $ 551,704 $ 575,692
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.................. . $1,396,196 $1,409,839 $1,759,780 $1,742,733 $1,869,358
========== ========== ========== ========== ==========
CAPITALIZATION RATIOS:
Common Stockholder's Equity............. 51.1% 45.2% 34.4% 31.7% 30.8%
Preferred Stock Not Subject to
Mandatory Redemption.................. 9.0 9.0 11.9 12.0 11.2
Long-Term Debt.......................... 39.9 45.8 53.7 56.3 58.0
----- ----- ------ ----- -----
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
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 that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
Corporate Separation
- --------------------
Beginning on January 1, 2001, Ohio customers were able to choose
their electricity suppliers as a result of legislation which restructured the
electric utility industry. That legislation required unbundling the price for
electricity into its component elements - including generation, transmission,
distribution and transition charges. 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
========================================================================================
<FN>
(a) Transfer of fossil operations to FirstEnergy Generation Company (FGCO).
(b) Purchased power from power supply agreement (PSA).
(c) Payroll taxes related to employees transferred to FGCO.
(d) Transmission services received from ATSI.
(e) Depreciation and property taxes related to transmission assets sold to ATSI.
(f) Interest on note receivable from ATSI.
</FN>
Results of Operations
- ---------------------
Earnings on common stock in 2002 decreased 96% to $2.0 million from
$46.8 million in 2001 and $121.0 million in 2000. Excluding the effects shown in
the table above, earnings on common stock increased by 4.1% in 2001 from 2000,
being favorably affected by reduced operating expenses and taxes, and lower net
interest charges, which were substantially offset by reduced operating revenues.
Operating revenues decreased by $107.3 million or 9.8% 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 table above, operating revenues
decreased by $54.7 million or 5.7% 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.
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 $56.9 million in 2002
and increased by $227.9 million in 2001 from 2000. Excluding the effects of
restructuring, total 2001 operating expenses and taxes were $48.0 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
- ---------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power...................... $(90.5) $(49.8)
Nuclear operating costs....................... 96.8 (16.5)
Other operating costs......................... 12.0 8.9
- ---------------------------------------------------------------------
Total operation and maintenance expenses.... 18.3 (57.4)
=====================================================================
Provision for depreciation and amortization... (36.7) 28.0
General taxes................................. (4.6) (27.7)
Income taxes.................................. (33.9) 9.1
- ---------------------------------------------------------------------
Total operating expenses and taxes.......... $(56.9) $(48.0)
=====================================================================
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 $12.0 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 increased by
$8.9 million in 2001 from the prior year, reflecting planned maintenance work at
the Bruce Mansfield Plant and the absence in 2001 of gains from the sale of
emission allowances, offset in part by 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 $36.7 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 of
Statement of Financial Accounting Standards No. (SFAS) 142 "Goodwill and Other
Intangible Assets." TE's goodwill amortization in 2001 totaled $ 12.4 million.
Depreciation and amortization increased by $28.0 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 $3.1
million in 2002 and $6.6 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.
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 51%
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 $223
Working capital and other 45 (33)
-------------------------------------------------------------
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 51% 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.
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
- --------------------------------------------------------------------------------------------------------------
<FN>
(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.
</FN>
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.
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. In conjunction with the adoption of SFAS 143,
"Accounting for Asset Retirement Obligations," on January 1, 2003, we
reclassified unrealized gains and losses to Other Comprehensive Income (OCI) in
accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances
will eventually affect earnings (affecting OCI initially) based on the guidance
provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from
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,
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 $392.6 million as of December 31,
2002 and $388.8 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 spring of 2003 after
completion of the additional maintenance work and regulatory reviews. The NRC
must authorize restart of the plant following its formal inspection process
before the unit can be returned to service. While the additional maintenance
work has delayed our plans to reduce post-merger debt levels we believe such
investments in the unit's future safety, reliability and performance to be
essential. Significant delays in Davis-Besse's return to service, which depends
on the successful resolution of the management and technical issues as well as
NRC approval could trigger an evaluation for impairment of our investment in the
plant (see Significant Accounting Policies below).
The actual costs (capital and expense) associated with the extended
Davis-Besse outage (TE share - 48.62%) in 2002 and estimated costs in 2003 are:
Costs of Davis-Besse Extended Outage 100%
-------------------------------------------------------------------------
(In millions)
2002 - Actual
-------------
Capital Expenditures:
Reactor head and restart ................................ $ 63.3
Incremental Expenses (pre-tax):
Maintenance ............................................. 115.0
Fuel and purchased power ................................ 119.5
-------------------------------------------------------------------------
Total ................................................... $234.5
=========================================================================
2003 - Estimated
----------------
Primarily operating expenses (pre-tax):
Maintenance (including acceleration of programs) ........ $50
Replacement power per month ............................. $12-18
-------------------------------------------------------------------------
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.
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 -- $392.6 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:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and
industrial customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions we make to the plans, and earnings on plan assets. Pension and
OPEB costs may also be affected by changes to key assumptions, including
anticipated rates of return on plan assets, the discount rates and health care
trend rates used in determining the projected benefit obligations and pension
and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect
the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently
available rates of return on high-quality fixed income investments expected to
be available during the period to maturity of the pension and other
postretirement benefit obligation. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, we reduced the assumed
discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75%
used in 2000.
Our assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by our pension trusts. The market values of our pension assets have been
affected by sharp declines in the equity markets since mid-2000. In 2002, 2001
and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our
pension costs in 2002 were computed assuming a 10.25% rate of return on plan
assets. As of December 31, 2002 the assumed return on plan assets was reduced to
9.00% based upon our projection of future returns and pension trust investment
allocation of approximately 60% large cap equities, 10% small cap equities and
30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, we will not be required to fund our pension plans in 2003. While OPEB
plan assets have also been affected by sharp declines in the equity market, the
impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates.
The effect on our SFAS 87 and 106 costs and liabilities from changes
in key assumptions are as follows:
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.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset, is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, we recognize a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
Goodwill
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate
our goodwill for impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value including goodwill, an impairment for goodwill must be recognized
in the financial statements. If
impairment were to occur we would recognize a loss - calculated as the
difference between the implied fair value of a reporting unit's goodwill and the
carrying value of the goodwill. Our annual review was completed in the third
quarter of 2002. The results of that review indicated no impairment of goodwill.
The forecasts used in our evaluations of goodwill reflect operations consistent
with our general business assumptions. Unanticipated changes in those
assumptions could have a significant effect on our future evaluations of
goodwill. As of December 31, 2002, we had approximately $445.7 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 $180.9 million, including unrealized
gains on decommissioning trust funds of $1.9 million. The change in the
estimated liabilities resulted from changes in methodology and various
assumptions, including changes in the projected dates for decommissioning.
The cumulative effect adjustment to recognize the undepreciated asset
retirement cost and the asset retirement liability offset by the reversal of the
previously recorded decommissioning liabilities was a 115.2 million increase to
income ($67.3 million net of tax). The $1.9 million of unrealized gains ($1.1
million net of tax) included in the decommissioning liability balances as of
December 31, 2002, were offset against OCI upon adoption of SFAS 143.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities"
This statement, which was issued by the FASB in July 2002, requires
the recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." This new standard was effective for exit and disposal
activities initiated after December 31, 2002. Since it is applied prospectively,
there will be no impact upon adoption. However, SFAS 146 could change the timing
and amount of costs recognized in connection with future exit or disposal
activities.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an interpretation of FASB
Statements No. 5, 57, and 107 and rescission of FASB Interpretation
No. 34"
The FASB issued FIN 45 in January 2003. This interpretation
identifies minimum guarantee disclosures required for annual periods ending
after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies
that providers of guarantees must record the fair value of those guarantees at
their inception. This accounting guidance is applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. We do not believe that
implementation of FIN 45 will be material but we will continue to evaluate
anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after
January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs
created before February 1, 2003 are subject to this interpretation's provisions
in the first interim or annual reporting period after June 15, 2003 (our third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
We currently have transactions with entities which may fall within the
scope of this interpretation and which are reasonably possible of meeting the
definition of a VIE in accordance with FIN 46. We currently consolidate the
majority of these entities and believe we will continue to consolidate following
the adoption of FIN 46. One of these entities we are currently consolidating is
the Shippingport Capital Trust which reacquired a portion of the off-balance
sheet debt issued in connection with the sale and leaseback of our interest in
the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent
interest by nonaffiliated parties and 0.34 percent equity interest by Toledo
Edison Capital Corp., a majority owned subsidiary.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (a) (Note 1).................................. $987,645 $1,094,903 $954,947
-------- ---------- --------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1)............................. 366,932 457,444 159,039
Nuclear operating costs (Note 1).............................. 258,308 161,532 178,063
Other operating costs (Note 1)................................ 163,267 151,244 156,286
-------- ---------- --------
Total operation and maintenance expenses.................... 788,507 770,220 493,388
Provision for depreciation and amortization................... 93,482 130,196 104,914
General taxes................................................. 53,223 57,810 90,837
Income taxes.................................................. (2,745) 31,193 72,394
-------- ---------- --------
Total operating expenses and taxes.......................... 932,467 989,419 761,533
-------- ---------- --------
OPERATING INCOME................................................. 55,178 105,484 193,414
OTHER INCOME (Note 1)............................................ 13,329 15,652 8,669
-------- ---------- --------
INCOME BEFORE NET INTEREST CHARGES............................... 68,507 121,136 202,083
-------- ---------- --------
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) (4,390) (1,519)
-------- ---------- --------
Net interest charges........................................ 55,170 58,225 64,850
-------- ---------- --------
NET INCOME....................................................... 13,337 62,911 137,233
PREFERRED STOCK DIVIDEND
REQUIREMENTS.................................................. 11,356 16,135 16,247
-------- ---------- --------
EARNINGS ON COMMON STOCK......................................... $ 1,981 $ 46,776 $120,986
======== ========== ========
<FN>
(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.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
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 9,709
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
---------- ----------
129,462 133,833
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................ 392,643 388,846
Goodwill..................................................................... 445,732 445,732
Property taxes............................................................... 23,429 23,836
Other........................................................................ 14,257 1,909
---------- ----------
876,061 860,323
---------- ----------
$2,617,224 $2,572,118
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................. $ 712,931 $ 637,665
Preferred stock not subject to mandatory redemption.......................... 126,000 126,000
Long-term debt............................................................... 557,265 646,174
---------- ----------
1,396,196 1,409,839
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock......................... 189,355 347,593
Accounts payable-
Associated companies....................................................... 171,862 53,960
Other...................................................................... 8,638 27,418
Notes payable to associated companies........................................ 149,653 17,208
Accrued taxes............................................................... 34,967 39,848
Accrued interest............................................................. 16,377 19,918
Other........................................................................ 57,232 40,222
---------- ----------
628,084 546,167
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes............................................ 223,087 213,145
Accumulated deferred investment tax credits.................................. 29,491 31,342
Nuclear plant decommissioning costs.......................................... 180,856 162,426
Pensions and other postretirement benefits................................... 82,553 120,561
Other........................................................................ 76,957 88,638
---------- ----------
592,944 616,112
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)..............................................................
---------- ----------
$2,617,224 $2,572,118
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
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)................................... (21,115) --
Retained earnings (Note 3A)...................................................... 109,817 113,436
---------- ----------
Total common stockholder's equity.............................................. 712,931 637,665
---------- ----------
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
---------- ----------
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (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.................................................................. $1,396,196 $1,409,839
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2002 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE 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
------------- --------- ----- ------- ------------- --------
(Dollars in thousands)
Balance, January 1, 2000............... 39,133,887 $195,670 $328,559 $ -- $ 27,475
Net income.......................... $137,233 137,233
========
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 -- 81,358
Net income.......................... $ 62,911 62,911
========
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 -- 113,436
Net income.......................... $ 13,337 13,337
Minimum liability for unfunded
retirement benefits, net of
$(15,042,000) of income taxes..... (21,115) (21,115)
--------
Comprehensive loss.................. $ (7,778)
========
Equity contribution from parent..... 100,000
Cash dividends on preferred stock... (10,057)
Cash dividends on common stock...... (5,600)
Preferred stock redemption premiums. (1,299)
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002............. 39,133,887 $195,670 $428,559 $(21,115) $109,817
=====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to
Mandatory Redemption
--------------------
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
====================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 13,337 $ 62,911 $ 137,233
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization................... 93,482 130,196 104,914
Nuclear fuel and lease amortization........................... 11,866 22,222 23,881
Deferred income taxes, net.................................... (5,868) 11,897 20,376
Investment tax credits, net................................... (1,851) (3,832) (1,827)
Receivables................................................... 13,564 (9,837) (6,671)
Materials and supplies........................................ (5,582) 8,336 4,093
Accounts payable.............................................. 42,501 19,744 13,997
Other (Note 7)................................................ (5,911) (51,781) (38,180)
--------- --------- ---------
Net cash provided from 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 provided from (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 provided from (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
========= ========= =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
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......................................................... $ 9,669 $ 25,640 $ 56,631
State........................................................... 2,957 5,937 1,811
-------- -------- --------
12,626 31,577 58,442
-------- -------- --------
Deferred, net-
Federal......................................................... (5,312) 11,736 20,865
State........................................................... (556) 161 (489)
-------- -------- --------
(5,868) 11,897 20,376
-------- -------- --------
Investment tax credit amortization................................. (1,851) (3,832) (1,827)
-------- -------- --------
Total provision for income taxes............................ $ 4,907 $ 39,642 $ 76,991
======== ======== ========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income................................................... $ (2,745) $ 31,193 $ 72,394
Other income....................................................... 7,652 8,449 4,597
-------- -------- --------
Total provision for income taxes............................ $ 4,907 $ 39,642 $ 76,991
======== ======== ========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes...................... $ 18,244 $102,553 $214,224
======== ======== ========
Federal income tax expense at statutory rate....................... $ 6,385 $ 35,894 $ 74,978
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit........... 1,561 3,964 859
Amortization of investment tax credits.......................... (1,851) (3,832) (1,827)
Amortization of tax regulatory assets........................... (1,969) (2,367) (1,737)
Amortization of goodwill........................................ -- 4,351 4,334
Other, net...................................................... 781 1,632 384
-------- -------- --------
Total provision for income taxes............................ $ 4,907 $ 39,642 $ 76,991
======== ======== ========
ACCUMULATED DEFERRED INCOME TAXES
AT DECEMBER 31:
Property basis differences......................................... $177,262 $171,976 $163,537
Competitive transition charge...................................... 121,392 135,462 70,264
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......................................... (15,042) -- --
Other (Note 7)..................................................... (63,297) (98,414) (30,398)
-------- -------- --------
Net deferred income tax liability............................... $223,087 $213,145 $196,944
======== ======== ========
<FN>
* 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.
</FN>
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.
(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 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.
(D) UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction (except for
the Company's nuclear generating units which were adjusted to fair value),
including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs. The Company's accounting
policy for planned major maintenance projects is to recognize liabilities as
they are incurred.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annualized composite rate was approximately 3.9% 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 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 $181 million, including unrealized gains on decommissioning trust
funds of $2 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 million increase to
income ($67 million net of tax). The $2 million of unrealized gains ($1 million
net of tax) included in the decommissioning liability balances as of December
31, 2002 was offset against as other comprehensive income (OCI) upon adoption of
SFAS 143.
The FASB approved SFAS 142, "Goodwill and Other Intangible Assets,"
on June 29, 2001. Under SFAS 142, amortization of existing goodwill ceased
January 1, 2002. Instead, goodwill is tested for impairment at least on an
annual basis - based on the results of the transition analysis and the 2002
annual analysis, no impairment of the Company's goodwill is required. 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 $12.4 million of goodwill annually. The goodwill balance as of December
31, 2002 and 2001 was $446 million.
The following table shows what net income would have been if goodwill
amortization had been excluded from prior periods:
2002 2001 2000
---- ---- ----
(In thousands)
Reported net income................... $13,337 $62,911 $137,233
Add back goodwill amortization........ -- 12,432 12,384
------- ------- --------
Adjusted net income................... $13,337 $75,343 $149,617
======= ======= ========
(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:
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.
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 .............................. $ 18.8 $ 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%
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2002 were computed as follows:
Other
Pension Benefits Postretirement Benefits
------------------------ ------------------------
2002 2001 2000 2002 2001 2000
-----------------------------------------------------------------------------------------------------
(In millions)
Service cost .......................... $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3
Interest cost ......................... 249.3 133.3 104.8 113.6 64.4 45.7
Expected return on plan assets ........ (346.1) (204.8) (181.0) (51.7) (9.9) (0.5)
Amortization of transition obligation
(asset) .............................. -- (2.1) (7.9) 9.2 9.2 9.2
Amortization of prior service cost .... 9.3 8.8 5.7 3.2 3.2 3.2
Recognized net actuarial loss (gain) .. -- -- (9.1) 11.2 4.9 --
Voluntary early retirement program .... -- 6.1 17.2 -- 2.3 --
-----------------------------------------------------------------------------------------------------
Net periodic benefit cost (income) .... $ (28.7) $(23.8) $ (42.9) $114.0 $92.4 $68.9
=====================================================================================================
Company's share of net benefit cost.... $ 0.7 $ (0.7) $ (12.7) $ 4.4 $ 3.5 $15.1
-----------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately
10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. An increase in the health care cost trend
rate assumption by one percentage point would increase the total service and
interest cost components by $20.7 million and the postretirement benefit
obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
(J) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily CEI, OE, Penn, ATSI,
FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The
Ohio transition plan, as discussed in the "Regulatory Plans" section, resulted
in the corporate separation of FirstEnergy's regulated and unregulated
operations in 2001. Unregulated operations under FES now operate the generation
businesses of the Company, CEI, OE and Penn. As a result, the Company entered
into power supply agreements (PSA) whereby FES purchases all of the Company's
nuclear generation and the generation from leased fossil generating facilities
and the Company purchases its power from FES to meet its "provider of last
resort" obligations. CFC serves as the transferor in connection with the
accounts receivable securitization for the Company and CEI. The primary
affiliated companies transactions, including the effects of the PSA beginning in
2001, the sale and leaseback of the Company's transmission assets to ATSI in
September 2000 and FirstEnergy's providing support services at cost, are as
follows:
2002 2001 2000
- -------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues with FES............... $128.2 $180.9 $ --
Generating units rent with FES...... 14.0 14.0 --
Electric sales to CEI............... 104.0 97.0 106.8
Ground lease with ATSI.............. 1.7 1.7 1.9
Operating Expenses:
Purchased power under PSA........... 319.0 388.0 --
Transmission expenses (including
ATSI rent)....................... 22.5 17.0 9.4
FirstEnergy support services........ 26.2 23.8 36.0
Other Income:
Interest income from ATSI........... 3.0 3.0 1.0
Interest income from FES............ 9.7 9.7 --
- -------------------------------------------------------------------------
FirstEnergy does not bill directly or allocate any of its costs to
any subsidiary company. Costs are allocated to the Company from its affiliates,
GPU Service, Inc. and FirstEnergy Service Company, both subsidiaries of
FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of
the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are
directly billed or assigned at no more than cost as determined by PUHCA Rule 91.
The remaining costs are for services that are provided on behalf of more than
one company, or costs that cannot be precisely identified and are allocated
using formulas that are filed annually with the SEC on Form U-13-60. The current
allocation or assignment formulas used and their bases include multiple factor
formulas; the ratio of each company's amount of FirstEnergy's aggregate direct
payroll, number of employees, asset balances, revenues, number of customers
and other factors; and specific departmental charge ratios. Management believes
that these allocation methods are reasonable.
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 the trust investment with a corresponding change to the
decommissioning liability. In conjunction with the adoption of SFAS 143 on
January 1, 2003, unrealized gains or losses were reclassified to 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. The Company recognized
incremental transition cost recovery aggregating $24 million in 2002 and $37
million in 2001 in accordance with the current Ohio transition plan.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2002 2001
- -------------------------------------------------------------------------
(In millions)
Regulatory transition costs...................... $396.5 $394.7
Loss on reacquired debt.......................... 3.0 3.2
Other............................................ (6.9) (9.1)
- --------------------------------------------------------------------------
Total..................................... $392.6 $388.8
=========================================================================
2. LEASES:
The Company leases certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.
The Company and CEI sold their ownership interests in Bruce Mansfield
Units 1, 2 and 3 and the Company sold a portion of its ownership interest in
Beaver Valley Unit 2. In connection with these sales, which were completed in
1987, the Company and CEI entered into operating leases for lease terms of
approximately 30 years as co-lessees. During the terms of the leases, the
Company and CEI continue to be responsible, to the extent of their combined
ownership and leasehold interest, for costs associated with the units including
construction expenditures, operation and maintenance expenses, insurance,
nuclear fuel, property taxes and decommissioning. The Company and CEI have the
right, at the end of the respective basic lease terms, to renew the leases. The
Company and CEI also have the right to purchase the facilities at the expiration
of the basic lease term or any renewal term at a price equal to the fair market
value of the facilities.
As co-lessee with CEI, the Company is also obligated for CEI's lease
payments. If CEI is unable to make its payments under the Bruce Mansfield Plant
lease, the Company would be obligated to make such payments. No such payments
have been made on behalf of CEI. (CEI's future minimum lease payments as of
December 31, 2002 were approximately $0.2 billion, net of trust cash receipts.)
Consistent with the regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 2002 are
summarized as follows:
2002 2001 2000
- ----------------------------------------------------------------------------
(In millions)
Operating leases
Interest element............... $ 52.6 $ 55.7 $ 58.7
Other.......................... 58.6 52.4 46.2
Capital leases
Interest element............... -- 2.5 3.9
Other.......................... 0.3 14.1 24.1
- --------------------------------------------------------------------------
Total rentals.................. $111.5 $124.7 $132.9
==========================================================================
The future minimum lease payments as of December 31, 2002 are:
Operating Leases
-----------------------------------
Lease Capital
Payments Trust Net
- -------------------------------------------------------------------------
(In millions)
2003............................. $ 111.7 $ 36.6 $ 75.1
2004............................. 97.9 24.6 73.3
2005............................. 104.8 25.3 79.5
2006............................. 107.8 26.0 81.8
2007............................. 99.2 22.6 76.6
Years thereafter................. 908.7 228.2 680.5
-------------------------------------------------------------------------
Total minimum lease payments..... $1,430.1 $363.3 $1,066.8
======== ====== ========
The Company and CEI refinanced high-cost fixed obligations related to
their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through
a lower cost transaction in June and July 1997. In a June 1997 offering
(Offering), the two companies pledged $720 million aggregate principal amount
($145 million for the Company and $575 million for CEI) of first mortgage bonds
due through 2007 to a trust as security for the issuance of a like principal
amount of secured notes due through 2007. The obligations of the two companies
under these secured notes are joint and several. Using available cash,
short-term borrowings and the net proceeds from the Offering, the two companies
invested $906.5 million ($337.1 million for the Company and $569.4 million for
CEI) in a business trust, in June 1997.
The trust used these funds in July 1997 to purchase lease notes and redeem all
$873.2 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease
obligations bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a
special-purpose funding corporation in 1988 on behalf of lessors in the two
companies' 1987 sale and leaseback transaction. The Shippingport Capital Trust
arrangement effectively reduces lease costs related to that transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
The Company has a provision in its mortgage that requires common
stock dividends to be paid out of its total balance of retained earnings.
(B) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
- --------------------------------------------------------------------------
Restricted common shares granted ...... 36,922 133,162 208,400
Weighted average market price ......... $36.04 $35.68 $26.63
Weighted average vesting period
(years) .............................. 3.2 3.7 3.8
Dividends restricted .................. Yes * Yes
- ---------------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
Stock option activities under the FE Programs for the past three
years were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
- ------------------------------------------------------------------------------
Balance, January 1, 2000 ............. 2,153,369 $25.32
(159,755 options exercisable) ........ 24.87
Options granted .................... 3,011,584 23.24
Options exercised .................. 90,491 26.00
Options forfeited .................. 52,600 22.20
Balance, December 31, 2000 .......... 5,021,862 24.09
(473,314 options exercisable) ........ 24.11
Options granted .................... 4,240,273 28.11
Options exercised .................. 694,403 24.24
Options forfeited .................. 120,044 28.07
Balance, December 31, 2001 ........... 8,447,688 26.04
(1,828,341 options exercisable) ...... 24.83
Options granted .................... 3,399,579 34.48
Options exercised .................. 1,018,852 23.56
Options forfeited .................. 392,929 28.19
Balance, December 31, 2002 .......... 10,435,486 28.95
(1,400,206 options exercisable) ...... 26.07
As of December 31, 2002, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1G - "Stock-Based Compensation."
(C) PREFERRED AND PREFERENCE STOCK-
Preferred stock may be redeemed by the Company in whole, or in part,
with 30-90 days' notice.
The preferred dividend rates on the Company's Series A and Series B
shares fluctuate based on prevailing interest rates and market conditions. The
dividend rates for both issues averaged 7% in 2002.
The Company has five million authorized and unissued shares of $25
par value preference stock.
(D) LONG-TERM DEBT-
The Company has a first mortgage indenture under which it issues from
time to time first mortgage bonds, secured by a direct first mortgage lien on
substantially all of its property and franchises, other than specifically
excepted property. The Company has various debt covenants under its financing
arrangements. The most restrictive of the debt covenants relate to the
nonpayment of interest and/or principal on debt which could trigger a default
and the maintenance of minimum fixed charge ratios and debt to capitalization
ratios. There also exists cross-default provisions among financing arrangements
of FirstEnergy and the Company.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
--------------------------------------------
2003................................. $189.4
2004................................. 268.7
2005................................. 31.6
2006................................. --
2007................................. 30.0
--------------------------------------------
Included in the table above are amounts for various variable interest
rate long-term debt which have provisions by which individual debt holders have
the option to "put back" or require the respective debt issuer to redeem their
debt at those times when the interest rate may change prior to its maturity
date. These amounts are $73 million, $54 million and $32 million in 2003, 2004
and 2005, respectively, which represents the next date at which the debt holders
may exercise this provision.
The Company's obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds. Certain pollution
control revenue bonds are entitled to the benefit of irrevocable bank letters of
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.
4. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As
of December 31, 2002, the Company had total short-term borrowings of $149.7
million from its affiliates. The average interest rate on short-term borrowings
outstanding as of December 31, 2002 and 2001, were 1.8% and 3.6%, respectively.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$169 million for property additions and improvements from 2003-2007, of which
approximately $54 million is applicable to 2003. Investments for additional
nuclear fuel during the 2003-2007 period are estimated to be approximately $34
million, of which approximately $12 million applies to 2003. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $40 million and $19 million, respectively, as the nuclear fuel is
consumed.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on its ownership and leasehold interests in Beaver Valley Unit 2, the
Davis Besse Station and the Perry Plant, the Company's maximum potential
assessment under the industry retrospective rating plan (assuming the other
affiliate co-owners contribute their proportionate shares of any assessments
under the retrospective rating plan) would be $77.9 million per incident but not
more than $8.8 million in any one year for each incident.
The Company is also insured as to its respective interests in Beaver
Valley Unit 2, Davis-Besse and Perry under policies issued to the operating
company for each plant. Under these policies, up to $2.75 billion is provided
for property damage and decontamination and decommissioning costs. The Company
has also obtained approximately $263.4 million of insurance coverage for
replacement power costs for its respective interests in Beaver Valley Unit 2,
Davis-Besse and Perry. Under these policies, the Company can be assessed a
maximum of approximately $14.6 million for incidents at any covered nuclear
facility occurring during a policy year which are in excess of accumulated funds
available to the insurer for paying losses.
The Company intends to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and replacement
costs and other such costs arising from a nuclear incident at any of the
Company's plants exceed the policy limits of the insurance in effect with
respect to that plant, to the extent a nuclear incident is determined not to be
covered by the Company's insurance policies, or to the extent such insurance
becomes unavailable in the future, the Company would remain at risk for such
costs.
(C) ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Company
with regard to air and water quality and other environmental matters. In
accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note
1,
generation operations and any related additional capital expenditures for
environmental compliance are the responsibility of FirstEnergy's competitive
services business unit.
The Company is required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Company cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Company believes it is in compliance with the current SO2 and
nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Company's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes
uniform reductions of NOx emissions (an approximate 85% reduction in utility
plant NOx emissions from projected 2007 emissions) across a region of nineteen
states and the District of Columbia, including Ohio and Pennsylvania, based on a
conclusion that such NOx emissions are contributing significantly to ozone
pollution in the eastern United States. State Implementation Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania submitted a SIP that requires compliance with the NOx budgets at
the Company's Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP
that requires compliance with the NOx budgets at the Company's Ohio facilities
by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals found constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating
ultra-fine particulates but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these regulations may be substantial and will depend if and how they are
ultimately implemented by the states in which the Company operates affected
facilities.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000,
the EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The Company has been named as a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, the Company's proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. The
Company has total accrued liabilities aggregating approximately $0.2 million as
of December 31, 2002.
The effects of compliance on the Company with regard to environmental
matters could have a material adverse effect on the Company's earnings and
competitive position. These environmental regulations affect the Company's
earnings and competitive position to the extent it competes with companies that
are not subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations. The
Company believes it is in material compliance with existing regulations but is
unable to predict whether environmental regulations will change and what, if
any, the effects of such change would be.
(D) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant applicable to the Company are described above.
6. SALE OF GENERATING ASSETS:
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale
had included the 648 MW Bay Shore Plant owned by the Company. On 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. OTHER INFORMATION:
The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001 and 2000:
(A) Consolidated Statements of Cash Flows
2002 2001 2000
---- ---- ----
(In Thousands)
Other Cash Flows from Operating Activities:
Accrued taxes............................... $ (4,881) $(17,671) $ 223
Accrued interest............................ (3,541) (28) (2,015)
Prepayments and other....................... 11,125 12,571 (1,220)
All other................................... (8,614) (46,653) (34,722)
-------- -------- --------
Other cash used for operating activities.. $ (5,911) $(51,781) $(38,180)
======== ======== ========
(B) Consolidated Statements of Taxes
2002 2001 2000
---- ---- ----
(In Thousands)
Other Accumulated Deferred Income Taxes
at December 31:
Retirement Benefits......................... $ (9,768) $(35,126) $(28,656)
All other................................... (53,529) (63,288) (1,742)
-------- -------- --------
Total-Other............................... $(63,297) $(98,414) $(30,398)
======== ======== ========
8. RECENTLY ISSUED ACCOUNTING STANDARDS:
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an interpretation of
FASB Statements No. 5, 57, and 107 and rescission of FASB
Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation
identifies minimum guarantee disclosures required for annual periods ending
after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies
that providers of guarantees must record the fair value of those guarantees at
their inception. This accounting guidance is applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. We do not believe that
implementation of FIN 45 will be material but we will continue to evaluate
anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject
to this interpretation's provisions beginning in the first interim or annual
reporting period after June 15, 2003 (our third quarter of 2003). The FASB also
identified transitional disclosure provisions for all financial statements
issued after January 31, 2003.
We currently have transactions with entities which may fall within the
scope of this interpretation and which are reasonably possible of meeting the
definition of a VIE in accordance with FIN 46. The Company currently
consolidates the majority of these entities and believes it will continue to
consolidate following the adoption of FIN 46. One of these entities it 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 0.34 percent
equity interest by Toledo Edison Capital Corp., a majority owned subsidiary.
9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
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(In millions)
Operating Revenues.......................... $244.1 $250.3 $269.9 $223.3
Operating Expenses and Taxes................ 234.5 216.2 244.8 236.9
- -------------------------------------------------------------------------------------------------------------
Operating Income (Loss)..................... 9.6 34.1 25.1 (13.6)
Other Income (Expense)...................... 4.4 3.7 4.0 1.1
Net Interest Charges........................ 14.7 14.8 14.5 11.2
- -------------------------------------------------------------------------------------------------------------
Net Income (Loss)........................... $ (0.7) $ 23.0 $ 14.6 $(23.7)
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Earnings (Loss) Applicable to Common Stock.. $ 5.4 $ 20.8 $ 12.4 $(25.8)
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March 31, June 30, September 30, December 31,
Three Months Ended 2001 2001 2001 2001
- -------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $271.6 $263.0 $306.5 $253.8
Operating Expenses and Taxes................ 243.3 229.6 278.9 237.6
- -------------------------------------------------------------------------------------------------------------
Operating Income............................ 28.3 33.4 27.6 16.2
Other Income................................ 3.8 2.2 3.9 5.7
Net Interest Charges........................ 15.9 12.6 15.1 14.6
- -------------------------------------------------------------------------------------------------------------
Net Income.................................. $ 16.2 $ 23.0 $ 16.4 $ 7.3
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Earnings on Common Stock.................... $ 12.2 $ 18.9 $ 12.4 $ 3.3
=============================================================================================================
Report of Independent Accountants
To the Stockholders and Board of Directors of The Toledo Edison Company:
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of The Toledo Edison
Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of
December 31, 2002, and the results of their operations and their cash flows for
the year then ended in conformity with accounting principles generally accepted
in the United States of America. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audit. We conducted our audit
of these statements in accordance with auditing standards generally accepted in
the United States of America, which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion. The consolidated financial
statements of The Toledo Edison Company and subsidiary as of December 31, 2001
and for each of the two years in the period ended December 31, 2001 were
audited by other independent accountants who have ceased operations. Those
independent accountants expressed an unqualified opinion on those financials
statements, before the revisions described in Note 1 to the 2002 consolidated
financial statements, in their report dated March 18, 2002.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for goodwill in 2002.
As discussed above, the consolidated financial statements of The Toledo Edison
Company and subsidiary as of December 31, 2001 and for each of the two years in
the period ended December 31, 2001 were audited by other independent accountants
who have ceased operations. As described in Note 1 to the consolidated financial
statements, revisions have been made to include the transitional disclosures
required by Statement of Financial Accounting Standards No. 142, Goodwill and
Other Intangible Assets, which was adopted by the Company as of January 1, 2002.
In our opinion the transitional disclosures for 2001 and 2000 are appropriate.
However, we were not engaged to audit, review, or apply any procedures to the
2001 and 2000 consolidated financial statements of the Company other than with
respect to such disclosures and, accordingly, we do not express an opinion or
any other form of assurance on the 2001 and 2000 consolidated financial
statements taken as a whole.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003
The following report is a copy of a report previously issued by Arthur Andersen
LLP and has not been reissued by Arthur Andersen LLP.
Report of Independent Public Accountants
To the Stockholders and Board of Directors of The Toledo Edison Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of The Toledo Edison Company (an Ohio corporation
and wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of December
31, 2001 and 2000, and the related consolidated statements of income, common
stockholder's equity, preferred stock, cash flows and taxes for each of the
three years in the period ended December 31, 2001. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of The Toledo Edison Company and
subsidiary as of December 31, 2001 and 2000, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2001, in conformity with accounting principles generally accepted in the
United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.