THE TOLEDO EDISON COMPANY
2003 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. The area it serves has a population of
approximately 0.8 million.
Contents Page
- -------- ----
Selected Financial Data........................................... 1
Management's Discussion and Analysis.............................. 2-13
Consolidated Statements of Income................................. 14
Consolidated Balance Sheets....................................... 15
Consolidated Statements of Capitalization......................... 16-17
Consolidated Statements of Common Stockholder's Equity............ 18
Consolidated Statements of Preferred Stock........................ 18
Consolidated Statements of Cash Flows............................. 19
Consolidated Statements of Taxes.................................. 20
Notes to Consolidated Financial Statements........................ 21-38
Report of Independent Auditors.................................... 39
THE TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA
2003 2002 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues........................ $ 932,847 $ 996,045 $1,086,503 $ 954,947 $ 921,159
========== ========== ========== ========== ==========
Operating Income.......................... $ 34,023 $ 36,699 $ 85,964 $ 194,325 $ 165,809
========== ========== ========== ========== ==========
Income (Loss) Before Cumulative
Effect of Accounting Change............. $ 19,930 $ (5,142) $ 42,691 $ 138,144 $ 101,982
========== ========== ========== ========== ==========
Net Income (Loss)......................... $ 45,480 $ (5,142) $ 42,691 $ 138,144 $ 101,982
========== ========== ========== ========== ==========
Earnings (Loss) on Common Stock........... $ 36,642 $ (15,898) $ 26,556 $ 121,897 $ 85,744
========== ========== ========== ========== ==========
Total Assets.............................. $2,855,398 $2,861,614 $2,875,908 $3,010,657 $2,663,428
========== ========== ========== ========== ==========
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder's Equity............... $ 749,521 $ 681,195 $ 629,805 $ 610,847 $ 557,853
Preferred Stock Not Subject to Mandatory
Redemption............................. 126,000 126,000 126,000 210,000 210,000
Long-Term Debt............................ 270,072 557,265 646,174 944,193 981,029
---------- ---------- ---------- ---------- ----------
Total Capitalization...................... $1,145,593 $1,364,460 $1,401,979 $1,765,040 $1,748,882
========== ========== ========== ========== ==========
CAPITALIZATION RATIOS AS OF DECEMBER 31:
Common Stockholder's Equity............... 65.4% 49.9% 44.6% 34.6% 31.8%
Preferred Stock Not Subject to Mandatory
Redemption............................. 11.0 9.2 9.0 11.9 12.0
Long-Term Debt............................ 23.6 40.9 46.4 53.5 56.2
----- ----- ----- ----- -----
Total Capitalization...................... 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
DISTRIBUTION KILOWATT-HOUR
DELIVERIES (Millions):
Residential............................... 2,312 2,427 2,258 2,183 2,127
Commercial................................ 2,771 2,702 2,667 2,380 2,236
Industrial................................ 5,097 5,280 5,397 5,595 5,449
Other..................................... 69 57 61 49 54
------ ------ ------ ------- -----
Total..................................... 10,249 10,466 10,383 10,207 9,866
====== ====== ====== ====== =====
CUSTOMERS SERVED:
Residential............................... 270,258 272,474 270,589 269,071 266,900
Commercial................................ 36,969 32,037 31,680 31,413 32,481
Industrial................................ 215 1,883 1,898 1,917 1,937
Other..................................... 451 468 443 598 398
------- ------- ------- ------- -------
Total..................................... 307,893 306,862 304,610 302,999 301,716
======= ======= ======= ======= =======
Number of Employees ...................... 446 508 507 539 977
1
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), adverse
regulatory or legal decisions and the outcome of governmental investigations,
availability and cost of capital, the continuing availability and operation of
generating units, the inability of the Davis-Besse Nuclear Power Station to
restart (including because of an inability to obtain a favorable final
determination from the Nuclear Regulatory Commission) in early 2004, inability
to accomplish or realize anticipated benefits from strategic goals, the ability
to improve electric commodity margins and to experience growth in the
distribution business, the ability to access the public securities market,
further investigation into the causes of the August 14, 2003, regional power
outage and the outcome, cost and other effects of present and potential legal
and administrative proceedings and claims related to the outage, a denial of or
material change to the Company's Application related to its Rate Stabilization
Plan, and other similar factors.
Restatements
- ------------
We restated our consolidated financial statements for the three years
ended December 31, 2002, to reflect a change in the method of amortizing costs
associated with the Ohio transition plan and to recognize above-market
liabilities of certain leased generation facilities. Financial comparisons
described below reflect the effect of these restatements on 2002 financial
results.
Results of Operations
- ---------------------
Earnings on common stock increased to $36.6 million in 2003 from a
loss of $15.9 million in 2002 and earnings of $26.6 million in 2001. Earnings on
common stock in 2003 included an after-tax credit of $25.6 million from the
cumulative effect of an accounting change due to the adoption of SFAS 143,
"Accounting for Asset Retirement Obligations." Income before the cumulative
effect was $19.9 million in 2003, compared to a loss of $5.1 million for the
same period of 2002. The increase in 2003 reflected lower fuel and purchased
power costs, other operating costs, depreciation and amortization and financing
costs and net proceeds of $12 million (pre-tax) from the settlement of our claim
against NRG Energy, Inc. (see Note 6), partially offset by lower operating
revenues and higher nuclear operating costs.
Operating revenues decreased by $63.2 million or 6.3% in 2003 from
2002. Reduced revenues resulted from lower kilowatt-hour sales due to milder
weather in the second and third quarters, continued sluggishness in the regional
economy and increased sales by alternative suppliers. The decline in revenues
primarily resulted from lower generation sales revenues from all retail customer
sectors. Kilowatt-hour sales to retail customers declined by 9.0% in 2003 from
2002, which reduced generation retail sales revenues by $49.8 million. Electric
generation services provided to retail customers by alternative suppliers as a
percent of total sales delivered in our service area increased 5.9 percentage
points in 2003. Sales revenues from wholesale customers decreased by $19.1
million in 2003 compared to 2002. Kilowatt-hour sales to the wholesale market
declined in 2003 due to reduced nuclear generation available for sale to
FirstEnergy Solutions (FES), an affiliated company. Distribution deliveries
decreased 2.1% in 2003 from 2002. However, higher unit prices resulted in
overall revenue increases from electricity throughput of $17.2 million when
compared to 2002. Transition plan incentives provided to customers to encourage
switching to alternative energy providers, reduced revenues by $7.3 million in
2003, compared to last year. These revenue reductions are deferred for future
recovery under our transition plan and do not materially affect current period
earnings.
Operating revenues decreased by $90.5 million or 8.3% in 2002,
compared with 2001. The lower revenues reflect the effects of a sluggish
national economy on our service area, shopping by Ohio customers for alternative
energy providers and decreases in wholesale revenues. Retail kilowatt-hour sales
declined by 11.4% in 2002 from the prior year, with declines in all customer
sectors (residential, commercial and industrial), resulting in a $34.4 million
reduction in generation sales revenue. Our lower generation kilowatt-hour sales
resulted primarily from customer choice in Ohio. Sales of electric generation by
alternative suppliers as a percent of total sales delivered in our franchise
area increased to 17.0% in 2002 from 5.6% in 2001. Distribution deliveries
increased 0.8% in 2002, compared with 2001, but revenues from electricity
throughput decreased by $11.1 million in 2002 from the prior year due to lower
unit prices. The higher distribution deliveries resulted from additional
residential and commercial demand due to warmer summer weather that was more
than offset by the effect that the weakened economy had on demand by the
industrial customers. Customer
2
shopping incentives further reduced operating revenues by $15.0 million in 2002
from the prior year. 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).
Changes in electric generation sales and distribution deliveries for
2003 and 2002 are summarized in the following table:
Changes in Kilowatt-Hour Sales 2003 2002
- --------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (9.0)% (11.4)%
Wholesale............................. (15.4)% (27.6)%
- -------------------------------------------------------------------
Total Electric Generation Sales......... (11.8)% (19.2)%
====================================================================
Distribution Deliveries:
Residential........................... (4.8)% 7.5%
Commercial and industrial ............ (1.4)% (1.0)%
- -------------------------------------------------------------------
Total Distribution Deliveries........... (2.1)% 0.8%
====================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $60.5 million in 2003
and by $41.2 million in 2002. The following table presents changes from the
prior year by expense category.
Operating Expenses and Taxes - Changes 2003 2002
- --------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power........................... $(32.5) $(90.5)
Nuclear operating costs............................ 2.3 96.8
Other operating costs.............................. (14.8) 7.2
- --------------------------------------------------------------------------
Total operation and maintenance expenses........ (45.0) 13.5
Provision for depreciation and amortization........ (21.4) (14.7)
General taxes...................................... (2.5) (4.6)
Income taxes....................................... 8.4 (35.4)
- ---------------------------------------------------------------------------
Total operating expenses and taxes............. $(60.5) $(41.2)
===========================================================================
Lower fuel and purchased power costs in 2003, compared with 2002,
resulted from reduced nuclear generation -down 19.9% - and reduced
kilowatt-hours required for customer needs which more than offset an increase in
unit costs. Increased nuclear costs resulted from incremental costs associated
with the extended Davis-Besse outage, unplanned work performed during the Perry
Plant's 56-day nuclear refueling outage (19.91% interest) in the Spring of 2003,
and the 28-day refueling outage at Beaver Valley Unit 2 (19.91% interest) in the
third quarter of 2003, compared with a 24-day refueling outage at Beaver Valley
Unit 2, in the first quarter of 2002. Lower other operating costs in 2003
reflect lower employee costs - specifically the absence of short-term incentive
compensation and reduced health care costs.
Lower fuel and purchased power costs in 2002, compared to 2001,
resulted from a $69.0 million reduction in purchased power from FES, reflecting
lower kilowatt-hours purchased due to reduced kilowatt-hour sales and lower unit
prices. Nuclear operating costs increased by $96.8 million in 2002, primarily
due to approximately $55.9 million of incremental Davis-Besse maintenance costs
related to the extended outage (see Davis-Besse Restoration). During 2002, costs
also included amounts incurred for refueling outages at two nuclear plants
(Beaver Valley Unit 2 and Davis-Besse), compared to only one outage (Perry) in
2001. The $7.2 million increase in other operating costs in 2002 resulted
principally from higher employee benefit costs, employee severance costs and
uncollectible accounts expense.
Charges for depreciation and amortization decreased by $ 21.4 million
in 2003, compared with 2002 primarily from five factors - higher shopping
incentive deferrals ($7.3 million), lower charges resulting from the
implementation of SFAS 143 ($14.8 million), revised service life assumptions for
generating plants ($11.0 million), a slight decline in amortization of
regulatory assets being recovered under our transition plan ($4.3 million) and
reduced regulatory asset deferrals ($4.4 million).
Charges for depreciation and amortization decreased by $14.7 million
in 2002 from 2001. This decrease reflects higher shopping incentive deferrals
and tax-related deferrals under the Ohio transition plan and the cessation of
goodwill amortization.
General taxes decreased in 2003 due to settled property tax claims
and in 2002 due to state tax changes in connection with the Ohio electric
industry restructuring.
3
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $18.9
million in 2003 and $3.8 million in 2002, compared to the prior years, due to
our debt paydown program.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, we recorded
an after-tax credit to net income of $25.6 million. We identified applicable
legal obligations as defined under the new accounting standard for nuclear power
plant decommissioning and reclamation of a sludge disposal pond at the Bruce
Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $41.1 million were recorded as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $5.5
million. The asset retirement obligation liability at the date of adoption was
$172 million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, we had
recorded decommissioning liabilities of $179.6 million. The cumulative effect
adjustment for unrecognized depreciation and accretion, offset by the reduction
in the existing decommissioning liabilities and the reversal of accumulated
estimated removal costs for non-regulated generation assets, resulted in a $43.8
million increase to income, or $25.6 million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
Our cash requirements in 2004 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without significantly 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.
Changes in Cash Position
As of December 31, 2003, we had $ 2.2 million of cash and cash
equivalents, compared with $20.7 million as of December 31, 2002. Cash and cash
equivalents included $2 million received in December 2003 which was included in
the NRG settlement claim sold in January 2004 (see Note 6) and $20 million used
for the redemption of long-term debt in January 2003 as of December 31, 2003 and
2002, respectively. The major sources for changes in these balances are
summarized below.
Cash Flows From Operating Activities
Cash provided by operating activities in 2003, 2002 and 2001 were as
follows:
Operating Cash Flows 2003 2002 2001
-----------------------------------------------------------------------
(in millions)
Cash earnings (1).................... $119 $142 $236
Working capital and other............ (21) 14 (46)
------------------------------------------------------------------------
Total................................ $ 98 $156 $190
=======================================================================
(1) Includes net income, depreciation and
amortization, deferred operating lease costs,
deferred income taxes, investment tax credits
and major noncash charges.
Net cash provided from operating activities decreased to $98 million
in 2003 compared to $156 million in 2002. The 2003 decrease in funds from
operating activities resulted from a decrease of $35 million from higher working
capital and other requirements (primarily due to a change in payables) and a $23
million decrease in cash earnings.
Cash Flows From Financing Activities
In 2003, the net cash provided from financing activities of $6.7
million primarily reflects short-term borrowings partially offset by long-term
debt redemptions.
4
The following table provides details regarding new issues and
redemptions during 2003 and 2002:
Securities Issued or Redeemed 2003 2002
------------------------------------------------------------------------
(in millions)
New Issues
----------
Pollution Control Notes..................... $ -- $ 20
Redemptions
-----------
Unsecured Notes............................. 7 135
Secured Notes............................... 183 44
Preferred Stock............................. -- 85
Other, principally redemption premiums...... 1 2
------------------------------------------------------------------------
191 266
Short-term Borrowings, Net....................... $206 $132
------------------------------------------------------------------------
We had approximately $21.6 million of cash and temporary investments
and approximately $356 million of short-term indebtedness as of December 31,
2003. We are currently precluded from issuing first mortgage bonds or preferred
stock based upon applicable earnings coverage tests.
We have the ability to borrow from our regulated affiliates and
FirstEnergy to meet our short-term working capital requirements. FirstEnergy
Service Company administers this money pool and tracks surplus funds of
FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the
money pool agreements must repay the principal, together with accrued interest,
within 364 days of borrowing the funds. The rate of interest is the same for
each company receiving a loan from the pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in
2003 was 1.47%.
Our access to capital markets and costs of financing are dependent on
the ratings of our securities and that of our holding company, FirstEnergy. The
following table shows our securities' ratings following the downgrade by Moody's
Investors Service in February 2004. The ratings outlook on all securities is
stable.
Ratings of Securities
- -------------------------------------------------------------------------------
Securities S&P Moody's Fitch
- -------------------------------------------------------------------------------
FirstEnergy Senior unsecured BB+ Baa3 BBB-
Toledo Edison Senior secured BBB- Baa2 BBB-
Senior unsecured BB+ Baa3 BB
Preferred stock BB Ba2 BB-
- ------------------------------------------------------------------------------
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of TE. Fitch announced
that the Rating Outlook is Stable for the securities of FirstEnergy, and all of
the securities of its electric utility operating companies. Fitch stated that
the changes to the long-term ratings were "driven by the high debt leverage of
the parent, FirstEnergy. Despite management's commitment to reduce debt related
to the GPU merger, subsequent cash flows have been vulnerable to unfavorable
events, slowing the pace of FirstEnergy's debt reduction efforts. The Stable
Outlook reflects the success of FirstEnergy's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On December 23, 2003, Standard & Poor's (S&P) lowered its corporate
credit ratings on FirstEnergy and its regulated utility subsidiaries to "BBB-"
from "BBB" and lowered FirstEnergy's senior unsecured debt rating to "BB+" from
"BBB-". TE's ratings were lowered one notch as well (see table above). The
ratings were removed from CreditWatch with negative implications, where they had
been placed by S&P on August 18, 2003, and the Ratings Outlook returned to
Stable. The rating action followed a revision in S&P's assessment of our
consolidated business risk profile to `6' from `5' (`1' equals low risk, `10'
equals high risk), with S&P citing operational and management challenges as well
as heightened regulatory uncertainty for its revision of our business risk
assessment score. S&P's rationale for its revisions of the ratings included
uncertainty regarding the timing of the Ohio Rate Plan filing (see State
Regulatory Matters), the pending final report on the August 14 blackout (see
Power Outage), the outcome of the remedial phase of litigation relating to the
Sammis plant, and the extended Davis-Besse outage and the related pending
subpoena (see Davis-Besse Restoration). S&P further stated that the restart of
Davis-Besse and a supportive Ohio Rate Plan extension will be vital positive
developments that would aid an upgrade of FirstEnergy's ratings. S&P's reduction
of the credit ratings in December 2003 triggered cash and letter-of-credit
collateral calls of FirstEnergy in addition to higher interest rates for some
outstanding borrowings.
5
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2. The ratings of TE were confirmed. Moody's said that the
lower ratings were prompted by: "1) high consolidated leverage with significant
holding company debt, 2) a degree of regulatory uncertainty in the service
territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
Cash Flows From Investing Activities
Net cash used for investing activities increased to $123 million in
2003 from $106 million in 2002. This change reflects an increase in loans to
associated companies partially offset by lower property additions.
Contractual Obligations
Our cash contractual obligations as of December 31, 2003 that we
consider firm obligations are as follows:
2005- 2007-
Contractual Obligations Total 2004 2006 2008 Thereafter
- -----------------------------------------------------------------------------------------------------------------
(in millions)
Long-term debt................... $ 540 $230 $ -- $ 30 $ 280
Short-term borrowings............ 356 356 -- -- --
Operating leases (1)............. 991 73 161 146 611
Purchases (2).................... 328 36 94 74 124
- --------------------------------------------------------------------------------------------------------------
Total....................... $2,215 $695 $255 $250 $1,015
- --------------------------------------------------------------------------------------------------------------
<FN>
(1) Operating lease payments are net of capital trust receipts of $326.8 million
(see Note 2).
(2) Fuel and power purchases under contracts with fixed or minimum
quantities and approximate timing.
</FN>
Our capital spending for the period 2004-2006 is expected to be about
$141 million (excluding nuclear fuel) of which $50 million applies to 2004.
Investments for additional nuclear fuel during the 2004-2006 period are
estimated to be approximately $42 million, of which about $13 million relates to
2004. During the same periods, our nuclear fuel investments are expected to be
reduced by approximately $42 million and $21 million, respectively, as the
nuclear fuel is consumed.
Off-Balance Sheet Arrangements
- ------------------------------
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, 2003, of these
sale and leaseback operating lease commitments, net of trust investments, total
$592 million. We sell substantially all of our retail customer receivables,
which provided $90 million of off-balance sheet financing as of December 31,
2003.
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 which 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
Year of Maturity 2004 2005 2006 2007 2008 after Total Value
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
- -------------------------------------------------------------------------------------------------------------------
Investments Other Than Cash
and Cash Equivalents-
Fixed Income............... $ 9 $134 $12 $ 9 $15 $287 $466 $509
Average interest rate...... 7.7% 7.8% 7.7% 7.7% 7.7% 6.7% 7.1%
___________________________________________________________________________________________________________________
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate.................... $230 $30 $143 $403 $427
Average interest rate ..... 7.9% 7.1% 7.6% 7.7%
Variable rate................. $137 $137 $137
Average interest rate...... 3.5% 3.5%
Short-term Borrowings......... $356 $356 $356
Average interest rate...... 1.8% 1.8%
- -------------------------------------------------------------------------------------------------------------------
6
Equity Price Risk
- -----------------
Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $145
million and $90 million as of December 31, 2003 and 2002, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$15 million reduction in fair value as of December 31, 2003 (see Note 1(K) -
Cash and Financial Instruments).
Outlook
- -------
Beginning in 2001, our customers were able to 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 those
customers not choosing to receive power from an alternative energy supplier
subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, 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 provider of last resort (PLR) responsibility to our
franchise customers through December 31, 2005.
Regulatory assets are costs which have been authorized by the PUCO
and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. Our regulatory assets as of December 2003 and 2002 are
$459 million and $545 million, respectively. All of our regulatory assets are
expected to continue to be recovered under the provisions of the transition
plan.
As part of the Ohio transition plan we are obligated to supply
electricity to customers who do not choose an alternative supplier. We are also
required to provide 160 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers who serve customers within our service area. Our
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in our franchise area.
On October 21, 2003, FirstEnergy's regulated subsidiaries filed an
application with the PUCO to establish generation service rates beginning
January 1, 2006, in response to expressed concerns by the PUCO about price and
supply uncertainty following the end of the market development period. The
filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate generation supply at
stable prices, and continuing our support of energy efficiency
and economic development efforts.
Under the first option, an auction would be conducted to secure
generation service for our Ohio customers. Beginning in 2006, customers would
pay market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of our support of energy-efficiency programs and the potential for
continuing the program to give preferred access to nonaffiliated entities to
generation capacity if shopping drops below 20%. Under the proposed plan, we are
requesting:
o Extension of the transition cost amortization period from 2007
to 2008;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
o Ability to initiate a request to increase generation rates under
certain limited conditions.
7
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. A decision is expected from the
PUCO in the Spring of 2004.
On November 25, 2003, the PUCO ordered FirstEnergy to file a plan
with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will
address certain problems identified by the U.S.-Canada Power System Outage Task
Force (in connection with the August 14, 2003 regional power outage) and
addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software, improve its control room training procedures and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (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) 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 made
significant management and human performance changes with the intent of
re-establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and efforts continued in 2003 to focus
on design enhancements to the unit's reliability and performance. We also
accelerated maintenance work that had been planned for future refueling and
maintenance outages. We installed a state-of-the-art leak-detection system
around the reactor, as well as modified high-pressure injection pumps. Testing
of the bottom of the reactor for leaks was completed in October 2003 and no
indication of leakage was discovered. The focus of activities now involves
management and human performance issues. As a result, incremental maintenance
and capital expenditures declined in 2003 as emphasis shifted to performance
issues; replacement power costs were higher in 2003. We anticipate that
Davis-Besse will be ready for restart in the first quarter of 2004. The NRC must
authorize restart of the plant following its formal inspection process before
the unit can be returned to service. Delays in Davis-Besse's return to service
contributed to S&P's reduction in our credit rating in the fourth quarter of
2003 (see Cash Flows from Financing Activities below).
Incremental costs associated with the extended Davis-Besse outage
(the Company's share - 48.62%) for 2003 and 2002 were as follows:
Costs of Davis-Besse Increase
Extended Outage 2003 2002 (Decrease)
- ----------------------------------------------------------------------------
(In millions)
Incremental Expense
Replacement power................. $196 $120 $ 76
Maintenance....................... 93 115 (22)
- ---------------------------------------------------------------------------
Total......................... $289 $235 $ 54
===========================================================================
Incremental Net of Tax Expense...... $170 $138 $ 32
===========================================================================
Capital Expenditures................ $ 21 $ 63 $(42)
===========================================================================
FirstEnergy anticipates spending $10 million in 2004 for remaining
non-capital restart activities, expected NRC inspection activities after
Davis-Besse's return to service and other related activities. No additional
capital expenditures related to the restoration are expected. Replacement power
costs are expected to be $15-20 million per month during the remaining period of
the outage. FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage. If there are significant
delays in the NRC approval process, replacement power costs will continue to be
incurred, adversely affecting our cash flows and results of operations.
Environmental Matters
We believe we are in material compliance with 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 from the Companies' Ohio and
Pennsylvania facilities. Various regulatory
8
and judicial actions have since sought to further define NOx reduction
requirements. 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 the 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.
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 subsequently determined 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; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of December 31, 2003, based on
estimates of the total costs of cleanup, our proportionate responsibility for
such costs and the financial ability of other nonaffiliated entities to pay. We
have accrued liabilities aggregating approximately $0.2 million as of December
31, 2003. We do not believe environmental remediation costs will have a material
adverse effect on our financial condition, cash flows or results of operations.
In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.
We cannot currently estimate the financial impact of climate change
policies although the potential restrictions on carbon dioxide (CO2) emissions
could require significant capital and other expenditures. However, the CO2
emissions per kilowatt-hour of electricity generated by the Company is lower
than many regional competitors due to the Company's diversified generation
sources which includes the low or non-CO2 emitting gas-fired and nuclear
generators.
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. FirstEnergy continues to
accumulate data and evaluate the status of its electrical system prior to and
during the outage event, and continues to cooperate with the U.S.-Canada Power
System Outage Task Force (Task Force) investigating the August 14th outage. The
interim report issued by the Task Force on November 18, 2003 concluded that the
problems leading to the outage began in FirstEnergy's service area.
Specifically, the interim report concludes, among other things, that the
initiation of the August 14th outage resulted from the coincidence on that
afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest Independent System Operator and PJM
Interconnection) to provide effective diagnostic support. FirstEnergy believes
that the interim report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14th outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with
the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct
problems identified by the Task Force as events contributing to the August 14th
outage and addressing how FirstEnergy proposed to upgrade its control room
computer hardware and software and improve the training of control room
operators to ensure that similar problems do not occur in the future. The PUCO,
in consultation with the North American Electric Reliability Council, will
review the plan before determining the next steps in the proceeding. On December
24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part
of Ohio's power grid. The study is to examine the stability of the grid in
critical points in the Cleveland and Akron areas; the status of projected power
reserves during summer 2004 through 2008; and the need for new transmission
lines or other grid projects. The FERC ordered the study to be completed within
120 days. At this time, it is unknown what the cost of such study will be, or
the impact of the results.
9
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against us, the most significant of which are
described above.
Critical Accounting Policies
- ----------------------------
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States (GAAP).
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting 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 the 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, a significant amount of
regulatory assets have been recorded - $459 million as of December 31, 2003. We
regularly 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-hours that have been delivered but not yet billed through
the end of the accounting period. 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
FirstEnergy's 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 FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
merger with GPU, Inc. in November 2001), which impacts employee demographics,
plan experience and other factors. Pension and OPEB costs are also 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 for pension and OPEB costs.
Plan amendments to retirement health care benefits in 2003 and 2002,
related to changes in benefits provided and cost-sharing provisions, which
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit 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.
10
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December
31, 2002 and 2001, respectively.
FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by their pension trusts. In 2003, 2002 and 2001, plan assets actually
earned 24.0%, (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in
2003 were computed assuming a 9.0% rate of return on plan assets based upon
projections of future returns and their pension trust investment allocation of
approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to the former GPU operating companies. Accordingly,
FirstEnergy requested an actuarial study to update the pension liabilities for
each of its subsidiaries. Based on the actuary's report, our accrued pension
costs as of June 30, 2003 decreased by $3 million. The corresponding adjustment
related to this change increased other comprehensive income and deferred income
taxes and decreased the payable to associated companies.
Due to the increased market value of our pension plan assets, we
reduced our minimum liability as prescribed by SFAS 87 as of December 31, 2003
by $13 million, recording a decrease of $3 million in an intangible asset and
crediting OCI by $6 million (offsetting previously recorded deferred tax
benefits by $4 million). The remaining balance in OCI of $9 million will reverse
in future periods to the extent the fair value of trust assets exceeds the
accumulated benefit obligation. The accrued pension cost was reduced to $13
million as of December 31, 2003.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund their pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. FirstEnergy's pension and OPEB expenses in 2004 are expected
to decrease by $38 million and $34 million, respectively. These reductions
reflect the actual performance of pension plan assets and amendments to the
health care benefits plan announced in early 2004 which result in employees and
retirees sharing more of the benefit costs. The reduction in OPEB costs for 2004
does not reflect the impact of the new Medicare law signed by President Bush in
December 2003 due to uncertainties regarding some of its new provisions (see
Note 1(I)). The 2003 and 2002 composite health care trend rate assumptions are
approximately 10%-12% gradually decreasing to 5% in later years. In determining
their trend rate assumptions, FirstEnergy included the specific provisions of
their health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in their health care plans, and
projections of future medical trend rates. The effect on FirstEnergy's pension
and OPEB 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% $ 10 $ 6 $ 16
Long-term return on assets... Decrease by 0.25% $ 8 $ 1 $ 9
Health care trend rate....... Increase by 1% na $26 $ 26
Increase in Minimum Liability
- -----------------------------
Discount rate................ Decrease by 0.25% $104 na $104
- ----------------------------------------------------------------------------------------------
Ohio Transition Cost Amortization
In connection with our Ohio transition plan, the PUCO determined
allowable transition costs based on amounts recorded on our regulatory books.
These costs exceeded those deferred or capitalized on our balance sheet prepared
under GAAP since they included certain costs which have not yet been incurred or
that were recognized on the regulatory financial statements (fair value purchase
accounting adjustments). We use an effective interest method for amortizing
transition costs, often referred to as a "mortgage-style" amortization. The
interest rate under this method is equal to the rate of return authorized by the
PUCO in the transition plan. In computing the transition cost amortization, we
include only the portion of the transition revenues associated with transition
costs included on the balance sheet prepared under GAAP. Revenues collected for
the off balance sheet costs and the return associated with these costs are
recognized as income when received.
Long-Lived Assets
In accordance with SFAS 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 might 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
11
recognized in the financial statements. If impairment 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
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), the goodwill is tested for impairment. If
impairment were indicated, we would recognize a loss - calculated as the
difference between the implied fair value of our goodwill and the carrying value
of the goodwill. Our annual review was completed in the third quarter of 2003,
with no impairment of goodwill indicated. The forecasts used in our evaluation
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, 2003, we had
approximately $505 million of goodwill.
Nuclear Decommissioning
In accordance with SFAS No. 143, we recognize an asset retirement
obligation (ARO) for the future decommissioning of our nuclear power plants. The
ARO liability represents an estimate of the fair value of our current obligation
related to nuclear decommissioning and the retirement of other assets. A fair
value measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. We used an expected cash flow approach (as
discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and
Present Value in Accounting Measurements") to measure the fair value of the
nuclear decommissioning ARO. This approach applies probability weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.
The scenarios consider settlement of the ARO at the expiration of the nuclear
power plants' current license and settlement based on an extended license term.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS ADOPTED
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. As required,
we adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to
as special-purpose entities effective December 31, 2003. We will adopt FIN 46R
for all other types of entities effective March 31, 2004.
We currently have transactions with entities in connection with sale
and leaseback arrangements which fall within the scope of this interpretation
and which meet the definition of a VIE in accordance with FIN 46R. In 1997, we
and The Cleveland Electric Illuminating Company (CEI), an affiliated company,
established the Shippingport Capital Trust (Shippingport) to purchase all of the
lease obligation bonds issued by the owner trusts in the Bruce Mansfield Plant
sale and leaseback transactions. Prior to the adoption of FIN 46R, the assets
and liabilities of the trust were included on a proportionate basis in the
financial statements of TE and CEI. Upon adoption of FIN 46R, CEI was determined
to be the primary beneficiary of Shippingport, and therefore consolidated the
entire trust as of December 31, 2003. This changed our Shippingport investment
of $220 million to an investment in collateralized lease bonds of $210 million
($9 million current). The $10 million difference represents the minority
interest included on the financial statements of CEI.
In reviewing the sale and leaseback arrangements, the Company also
evaluated its interest in the owner trusts that acquired interests in the Bruce
Mansfield Plant. The Company was determined not to be the primary beneficiary of
any of these owner trusts and was therefore not required to consolidate these
entities. The leases are accounted for as operating leases in accordance with
GAAP and their related obligations are disclosed in Note 2.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, we implemented SFAS 143 which provides accounting
standards for retirement obligations associated with tangible long-lived assets.
This statement requires recognition of the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. See Notes
1(F) and 1(M) for further discussions of SFAS 143.
12
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary
Impairment and its Application to Certain Investments"
In November 2003, the EITF reached consensus that certain
quantitative and qualitative disclosures are required for debt and equity
securities classified as available-for-sale or held-to-maturity. The guidance
requires the disclosure of the aggregate amount of unrealized losses and the
aggregate related fair value for investments with unrealized losses that have
not been recognized as other-than-temporary impairments. We adopted the
disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See Note
1(K)).
13
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (a) (Note 1(J))............................... $932,847 $996,045 $1,086,503
-------- -------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1(J)).......................... 334,409 366,932 457,444
Nuclear operating costs....................................... 254,986 252,608 155,832
Other operating costs (Note 1(J))............................. 127,148 141,997 134,744
-------- -------- ----------
Total operation and maintenance expenses.................... 716,543 761,537 748,020
Provision for depreciation and amortization................... 140,613 162,082 176,796
General taxes................................................. 50,742 53,223 57,810
Income taxes (benefit)........................................ (9,074) (17,496) 17,913
-------- -------- ----------
Total operating expenses and taxes.......................... 898,824 959,346 1,000,539
-------- -------- ----------
OPERATING INCOME................................................. 34,023 36,699 85,964
OTHER INCOME (Notes 1(J) and 6).................................. 22,195 13,329 15,652
-------- -------- ----------
INCOME BEFORE NET INTEREST CHARGES............................... 56,218 50,028 101,616
-------- -------- ----------
NET INTEREST CHARGES:
Interest on long-term debt.................................... 38,874 58,120 66,463
Allowance for borrowed funds used during
construction................................................ (5,838) (2,502) (3,848)
Other interest expense (credit)............................... 3,252 (448) (3,690)
-------- -------- ----------
Net interest charges........................................ 36,288 55,170 58,925
-------- -------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE............................................. 19,930 (5,142) 42,691
Cumulative effect of accounting change (net of income taxes
of $18,201,000) (Note (1M))................................... 25,550 -- --
-------- -------- ----------
NET INCOME (LOSS)................................................ 45,480 (5,142) 42,691
PREFERRED STOCK DIVIDEND
REQUIREMENTS.................................................. 8,838 10,756 16,135
-------- -------- ----------
EARNINGS (LOSS) ON COMMON STOCK.................................. $ 36,642 $(15,898) $ 26,556
======== ======== ==========
<FN>
(a) Includes electric sales to associated companies of $212 million, $232 million and $278 million in
2003, 2002 and 2001, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
14
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 2002
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service.................................................................... $1,714,870 $1,600,860
Less-Accumulated provision for depreciation................................... 721,754 673,367
---------- ----------
993,116 927,493
---------- ----------
Construction work in progress-
Electric plant.............................................................. 125,051 104,091
Nuclear fuel................................................................ 20,189 33,650
---------- ----------
145,240 137,741
---------- ----------
1,138,356 1,065,234
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 2)........................................... 200,938 240,963
Nuclear plant decommissioning trusts.......................................... 240,634 174,514
Long-term notes receivable from associated companies.......................... 163,626 162,159
Other......................................................................... 2,119 2,236
---------- ----------
607,317 579,872
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents..................................................... 2,237 20,688
Receivables-
Customers................................................................... 4,083 4,711
Associated companies........................................................ 29,158 55,245
Other....................................................................... 14,386 6,778
Notes receivable from associated companies.................................... 19,316 1,957
Materials and supplies, at average cost-
Owned....................................................................... 35,147 13,631
Under consignment........................................................... -- 22,997
Prepayments and other......................................................... 6,704 3,455
---------- ----------
111,031 129,462
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................. 459,040 544,838
Goodwill...................................................................... 504,522 504,522
Property taxes................................................................ 24,443 23,429
Other......................................................................... 10,689 14,257
---------- ----------
998,694 1,087,046
---------- ----------
$2,855,398 $2,861,614
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity................................................... $ 749,521 $ 681,195
Preferred stock not subject to mandatory redemption........................... 126,000 126,000
Long-term debt................................................................ 270,072 557,265
---------- ----------
1,145,593 1,364,460
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.............................................. 283,650 189,355
Short-term borrowings......................................................... 70,000 --
Accounts payable-
Associated companies........................................................ 132,876 171,862
Other....................................................................... 2,816 9,338
Notes payable to associated companies......................................... 285,953 149,653
Accrued taxes................................................................ 55,604 34,676
Accrued interest.............................................................. 12,412 16,377
Lease market valuation liability.............................................. 24,600 24,600
Other......................................................................... 37,299 57,462
---------- ----------
905,210 653,323
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes............................................. 201,954 158,279
Accumulated deferred investment tax credits................................... 27,200 29,255
Retirement benefits........................................................... 47,006 82,553
Asset retirement obligation................................................... 181,839 --
Nuclear plant decommissioning costs........................................... -- 179,587
Lease market valuation liability.............................................. 292,600 317,200
Other......................................................................... 53,996 76,957
---------- ----------
804,595 843,831
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)...............................................................
---------- ----------
$2,855,398 $2,861,614
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
</FN>
15
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
(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............................................................ 428,559 428,559
Accumulated other comprehensive income (loss) (Note 3(E))........................ 11,672 (20,012)
Retained earnings (Note 3(A)).................................................... 113,620 76,978
---------- ----------
Total common stockholder's equity.............................................. 749,521 681,195
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
--------------------- ----------------------
2003 2002 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3(C)):
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
--------- --------- -------- ---------- ----------
310,000 310,000 31,990 31,000 31,000
--------- --------- -------- ---------- ----------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$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 3,800,000 98,850 95,000 95,000
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption.................... 4,110,000 4,110,000 $130,840 126,000 126,000
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3(D)):
First mortgage bonds:
8.000% due 2003................................................................ -- 33,725
7.875% due 2004................................................................ 145,000 145,000
---------- ----------
Total first mortgage bonds..................................................... 145,000 178,725
---------- ----------
Unsecured notes and debentures:
10.000% due 2004-2010............................................................ -- 910
* 4.850% due 2030................................................................ 34,850 34,850
4.000% due 2033................................................................ -- 5,700
* 4.500% due 2033................................................................ 31,600 31,600
* 5.580% due 2033................................................................ 18,800 18,800
---------- ----------
Total unsecured notes and debentures........................................... 85,250 91,860
---------- ----------
16
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2003 2002
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
7.760% due 2003.................................................................. -- 5,000
7.780% due 2003.................................................................. -- 1,000
7.820% due 2003.................................................................. -- 38,400
7.850% due 2003.................................................................. -- 15,000
7.910% due 2003.................................................................. -- 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
6.875% due 2023.................................................................. -- 20,200
8.000% due 2023.................................................................. 30,500 30,500
1.700% due 2024.................................................................. -- 67,300
6.100% due 2027.................................................................. 10,100 10,100
5.375% due 2028.................................................................. 3,751 3,751
* 1.150% due 2033.................................................................. 30,900 30,900
* 1.100% due 2033.................................................................. 20,200 20,200
---------- ----------
Total secured notes............................................................ 309,451 459,351
---------- ----------
Net unamortized premium on debt....................................................... 14,021 16,684
---------- ----------
Long-term debt due within one year.................................................... (283,650) (189,355)
---------- ----------
Total long-term debt........................................................... 270,072 557,265
---------- ----------
TOTAL CAPITALIZATION.................................................................. $1,145,593 $1,364,460
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2003 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
17
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, 2001............... 39,133,887 $195,670 $328,559 $ -- $ 86,618
Net income.......................... $ 42,691 42,691
Unrealized gain on investments, net
of $4,800,000 of income taxes..... 7,100 7,100
--------
Comprehensive income................ $ 49,791
========
Cash dividends on preferred stock... (16,133)
Cash dividends on common stock...... (14,700)
- -----------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001............. 39,133,887 195,670 328,559 7,100 98,476
Net loss............................ $ (5,142) (5,142)
Unrealized loss on investments, net
of $(4,034,000) of income taxes... (5,997) (5,997)
Minimum liability for unfunded
retirement benefits, net of
$(15,042,000) of income taxes..... (21,115) (21,115)
--------
Comprehensive loss.................. $(32,254)
Equity contribution from parent..... 100,000
Cash dividends on preferred stock... (9,457)
Cash dividends on common stock...... (5,600)
Preferred stock redemption premiums. (1,299)
- -----------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002............. 39,133,887 195,670 428,559 (20,012) 76,978
Net income.......................... $ 45,480 45,480
Unrealized gain on investments, net
of $13,908,000 of income taxes.... 19,988 19,988
Minimum liability for unfunded
retirement benefits, net of
$8,489,000 of income taxes........ 11,696 11,696
--------
Comprehensive income................ $ 77,164
Cash dividends on preferred stock... (8,838)
- -----------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003............. 39,133,887 $195,670 $428,559 $ 11,672 $113,620
=======================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to
Mandatory Redemption
--------------------
Number
of Shares Value
--------- -----
(Dollars in thousands)
Balance, January 1, 2001....... 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
---------------------------------------------------------
Balance, December 31, 2003..... 4,110,000 $126,000
=========================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
18
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss).................................................. $ 45,480 $ (5,142) $ 42,691
Adjustments to reconcile net income (loss) to net
cash from operating activities:
Provision for depreciation and amortization................... 140,613 162,082 176,796
Nuclear fuel and capital lease amortization................... 9,289 11,866 22,222
Deferred operating lease costs, net........................... (37,001) (24,600) (24,600)
Deferred income taxes, net.................................... 5,619 (24,821) (1,383)
Amortization of investment tax credits........................ (2,056) (1,851) (3,832)
Accrued retirement benefit obligation......................... 6,205 (59,123) 1,234
Accrued compensation, net..................................... (5,365) 2,614 (8,178)
Cumulative effect of accounting change (Note 1(M))............ (43,751) -- --
Receivables................................................... 19,107 5,164 (1,437)
Materials and supplies........................................ 1,481 (5,582) 8,336
Accounts payable.............................................. (53,765) 40,801 22,144
Accrued taxes................................................. 20,928 (4,881) (17,671)
Accrued interest.............................................. (3,965) (3,541) (28)
Prepayments and other current assets.......................... (3,249) 11,125 12,571
Other......................................................... (1,398) 51,427 (39,009)
--------- --------- ---------
Net cash provided from operating activities................. 98,172 155,538 189,856
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt................................................ -- 19,580 --
Short-term borrowings, net.................................... 206,300 132,445 --
Equity contributions from parent.............................. -- 100,000 --
Redemptions and Repayments-
Preferred stock............................................... -- (85,299) --
Long-term debt................................................ (190,794) (180,368) (42,265)
Short-term borrowings, net.................................... -- -- (24,728)
Dividend Payments-
Common stock.................................................. -- (5,600) (14,700)
Preferred stock............................................... (8,844) (10,057) (16,135)
--------- --------- ---------
Net cash provided from (used for) financing activities...... 6,662 (29,299) (97,828)
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions................................................. (84,924) (105,510) (112,451)
Loan payments from (to) associated companies, net.................. (18,826) 5,838 25,185
Investment in lessor notes......................................... 40,025 21,168 17,705
Contributions to nuclear decommissioning trust..................... (28,541) (28,541) (28,541)
Other.............................................................. (31,019) 1,192 4,991
--------- --------- ---------
Net cash used for investing activities...................... (123,285) (105,853) (93,111)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... (18,451) 20,386 (1,083)
Cash and cash equivalents at beginning of period................... 20,688 302 1,385
--------- --------- ---------
Cash and cash equivalents at end of period......................... $ 2,237 $ 20,688 $ 302
========= ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................... $ 38,576 $ 61,498 $ 63,159
========= ========= =========
Income taxes (refund)........................................... $ (9,257) $ 3,561 $ 33,210
========= ========= =========
<FN>
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.
</FN>
19
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property......................................... $ 18,488 $ 22,737 $ 23,624
Ohio kilowatt-hour excise*......................................... 29,793 28,046 19,576
State gross receipts*.............................................. -- -- 12,789
Social security and unemployment................................... 1,861 1,684 1,128
Other.............................................................. 600 756 693
--------- --------- ---------
Total general taxes......................................... $ 50,742 $ 53,223 $ 57,810
========= ========= =========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal......................................................... $ 15,495 $ 12,845 $ 22,244
State........................................................... 4,537 3,983 4,840
--------- --------- ---------
20,032 16,828 27,084
--------- --------- ---------
Deferred, net-
Federal......................................................... 4,414 (19,091) 4,725
State........................................................... 1,205 (5,570) (1,539)
--------- --------- ---------
5,619 (24,661) 3,186
--------- --------- ---------
Investment tax credit amortization................................. (2,056) (2,011) (3,908)
--------- --------- ---------
Total provision for income taxes............................ $ 23,595 $ (9,844) $ 26,362
========= ========= =========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income................................................... $ (9,074) $ (17,496) $ 17,913
Other income....................................................... 14,468 7,652 8,449
Cumulative effect of accounting change............................. 18,201 -- --
--------- --------- ---------
Total provision for income taxes............................ $ 23,595 $ (9,844) $ 26,362
========= ========= =========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes...................... $ 69,075 $ (14,986) $ 69,053
========= ========= =========
Federal income tax expense at statutory rate....................... $ 24,176 $ (5,245) $ 24,169
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit........... 3,732 (1,031) 2,146
Amortization of investment tax credits.......................... (2,056) (2,011) (3,908)
Amortization of tax regulatory assets........................... (2,397) (2,362) (2,563)
Amortization of goodwill........................................ -- -- 4,911
Other, net...................................................... 140 805 1,607
--------- --------- ---------
Total provision for (benefit from) income taxes............. $ 23,595 $ (9,844) $ 26,362
========= ========= =========
ACCUMULATED DEFERRED INCOME TAXES
AS OF DECEMBER 31:
Property basis differences......................................... $ 193,409 $ 177,262 $ 171,976
Regulatory transition charge....................................... 151,129 196,812 239,088
Unamortized investment tax credits................................. (10,472) (11,414) (12,184)
Deferred gain for asset sale to affiliated company................. 12,618 14,186 16,305
Other comprehensive income......................................... 8,121 (14,276) 4,800
Above market leases................................................ (130,231) (140,399) (150,634)
Retirement benefits................................................ (4,568) (9,768) (35,126)
Other.............................................................. (18,052) (54,124) (63,861)
--------- --------- ---------
Net deferred income tax liability............................... $ 201,954 $ 158,279 $ 170,364
========= ========= =========
<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>
20
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 financing related to the Bruce Mansfield
Plant sale and leaseback transactions (see Note 2). The Cleveland Electric
Illuminating Company (CEI), an affiliate, has a 10% interest in TECC. The
Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds
directly all of the issued and outstanding common shares of its other principal
electric utility operating subsidiaries, including 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).
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. The Company's
consolidated financial statements for the years ended December 31, 2002 and 2001
were restated to reflect a change in the method of amortizing costs being
recovered under the Ohio transition plan, recognition of above-market
liabilities of certain leased generation facilities, Ohio transition plan
regulatory assets and goodwill. Certain prior year amounts have been
reclassified to conform with the current year presentation, as described further
in Notes 1(F).
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, over which
the Company exercises control and, when applicable, entities for which the
Company has a controlling financial interest. Intercompany transactions and
balances are eliminated in consolidation. Investments in nonconsolidated
affiliates (20-50 percent owned companies, joint ventures and partnerships) over
which the Company has the ability to exercise significant influence, but not
control, are accounted for on the equity basis.
(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 provided
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 as of
December 31, 2003 or 2002, with respect to any particular segment of the
Company's customers. Total customer receivables were $4.0 million (billed - $2
million and unbilled - $2 million) and $5 million (billed - $3 million and
unbilled - $2 million) as of December 31, 2003 and 2002, respectively.
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 qualified special
purpose entity") under Statement of Financial Accounting Standards (SFAS) No.
140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishment of Liabilities," under an asset-backed securitization agreement.
Transfers are made in return for an interest in the trust (19% as of December
31, 2003), 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,
"Accounting for Certain Investments in Debt and Equity Securities", (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 FirstEnergy's retained
interest in the pool of receivables through the trust. Of the $250 million sold
to the trust and outstanding as of December 31, 2003, FirstEnergy had a retained
interest in $48 million of the receivables included as other receivables on the
Consolidated Balance Sheets. Accordingly, receivables recorded on FirstEnergy's
Consolidated Balance Sheets were reduced by approximately $202 million due to
these sales. Collections of receivables previously transferred to the trust and
used for the purchase of new receivables from CFC during 2003, totaled
approximately $2.4 billion. The Company and CEI processed receivables for the
trust and received servicing fees of approximately $3.6 million ($1.2 million TE
and $2.4 million CEI) in 2003. Expenses associated with the factoring discount
related to the sale of receivables were $3.5 million, $4.7 million and $12.0
million in 2003, 2002 and 2001, respectively.
21
(C) REGULATORY MATTERS-
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 (Ohio Companies) 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, which runs through
the end of 2005, 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. Subject to approval by the PUCO, recovery will be
accomplished by extending the transition cost recovery period.
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing
FirstEnergy's support of energy efficiency and economic
development efforts.
Under the first option, an auction would be conducted to secure
generation service for the Ohio Companies' customers. Beginning in 2006,
customers would pay market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of the Company's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity if shopping drops below 20%. Under the proposed
plan, TE is requesting:
o Extension of the transition cost amortization period from
mid-2007 to mid-2008;
o Deferral of interest costs on the accumulated shopping incentive
and other cost deferrals as new regulatory assets; and
o Ability to initiate a request to increase generation rates only
under certain limited conditions.
22
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. A decision is expected from the
PUCO in the Spring of 2004.
On November 25, 2003, the PUCO ordered FirstEnergy to file a plan
with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will
address certain problems identified by the U.S.-Canada Power System Outage Task
Force (in connection with the August 14, 2003 regional power outage) and
addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software, improve its control room training procedures and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding.
Transition Cost Amortization-
The Company amortizes transition costs (see Regulatory Matters) using
the effective interest method. Under the current Ohio transition plan, total
transition cost amortization is expected to approximate the following for 2004
through 2007.
(In millions)
- ---------------------------------
2004.................. $130
2005.................. 150
2006.................. 96
2007.................. 63
- --------------------------------
Regulatory Assets-
The Company recognizes, as regulatory assets, costs which the FERC
and the 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 remain regulated; accordingly, it is appropriate that the
Company continues the application of SFAS 71 to those operations.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2003 2002
- -----------------------------------------------------------------------
(In millions)
Regulatory transition costs...................... $447 $558
Customer shopping incentives..................... 52 24
Customer receivables for future income taxes..... (13) (16)
Loss on reacquired debt.......................... 3 3
Employee postretirement benefit costs............ 8 9
Component removal costs and all other............ (38) (33)
- ------------------------------------------------------------------------
Total..................................... $459 $545
=======================================================================
Regulatory Accounting for Generation Operations-
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 providing that any supplemental regulated cash
flows such as a competitive transition charge should be excluded from the cash
flows of assets in a portion of the business not subject to regulatory
accounting practices. If those assets are impaired, a regulatory asset should be
established if the costs are recoverable through regulatory cash flows.
Consistent with the SEC guidance $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 $561 million as of December 31, 2003.
(D) UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction (except for
the Company's nuclear generating units which were adjusted to fair value in
connection with the purchase accounting and impairment tests prepared in
connection with the transition plan), including payroll and related costs such
as taxes, employee benefits, administrative and general costs, and interest
costs incurred to place the assets in service. The Company's accounting policy
for planned major maintenance projects is to recognize liabilities as they are
incurred.
23
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 3.0% in 2003, 3.9% in 2002 and
3.5% in 2001.
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.
(E) COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, together with CEI, OE and OE's 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 as of December
31, 2003 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............... $ 65 $ 20 $ 18 18.61%
Beaver Valley Unit 2.......... 10 1 11 19.91%
Davis-Besse................... 249 58 79 48.62%
Perry......................... 354 68 4 19.91%
- ---------------------------------------------------------------------------------------------------
Total....................... $678 $147 $112
===================================================================================================
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) ASSET RETIREMENT OBLIGATION-
In January 2003, the Company implemented SFAS 143, "Accounting for
Asset Retirement Obligations," which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement requires recognition of the fair value of a liability for an asset
retirement obligation (ARO) 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 instead if the criteria for such treatment are met. Upon retirement, a
gain or loss would be recognized if the cost to settle the retirement obligation
differs from the carrying amount.
The Company identified applicable legal obligations as defined under
the new standard for nuclear power plant decommissioning and reclamation of a
sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as
of the date of adoption of SFAS 143 was $172 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. Accretion during 2003 was $9.8 million, bringing the ARO liability as
of December 31, 2003 to $181.8 million. The ARO includes the Company's
obligation for nuclear decommissioning of the Beaver Valley Unit 2, Davis-Besse,
and Perry nuclear generating facilities. The Company's share of the obligation
to decommission these units was developed based on site-specific studies
performed by an independent engineer. The Company utilized an expected cash flow
approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow
Information and Present Value in Accounting Measurements") to measure the fair
value of the nuclear decommissioning ARO. The Company maintains nuclear
decommissioning trust funds that are legally restricted for purposes of settling
the nuclear decommissioning ARO. As of December 31, 2003, the fair value of the
decommissioning trust assets was $240.6 million.
In accordance with SFAS 143, the Company ceased the accounting
practice of depreciating non-regulated generation assets using a cost of removal
component in the depreciation rates. That practice recognized accumulated
depreciation in excess of the historical cost of an asset because the removal
cost would exceed the estimated salvage value. Beginning in 2003, the cost of
removal related to non-regulated generation assets is charged to expense rather
than to the accumulated provision for depreciation. In accordance with SFAS 71,
the cost of removal on regulated plant assets continues to be accounted for as a
component of depreciation rates and is recognized as a regulatory liability.
24
The following table provides the effect on income as if SFAS 143 had
been applied during 2002 and 2001.
Effect of the Change in Accounting
Principle Applied Retroactively 2002 2001
- -----------------------------------------------------------------------------
(In millions)
Reported net income (loss)................................ $(5) $ 43
Increase (Decrease):
Elimination of decommissioning expense.................... 29 28
Depreciation of asset retirement cost..................... (1) (1)
Accretion of ARO liability................................ (11) (10)
Non-regulated generation cost of removal component, net... 1 1
Income tax effect......................................... (7) (7)
- -----------------------------------------------------------------------------
Net earnings increase..................................... 11 11
- -----------------------------------------------------------------------------
Net income adjusted....................................... $ 6 $ 54
=============================================================================
The following table provides the year-end balance of the ARO for
2002, as if SFAS 143 had been adopted on January 1, 2002.
Adjusted ARO Reconciliation 2002
- --------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2002 $161.1
Accretion in 2002 10.9
- ------------------------------------------------------
Ending balance as of December 31, 2002 $172.0
- ------------------------------------------------------
(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 3(B)). 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 of SFAS 123, "Accounting for Stock Compensation," 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:
2003 2002 2001
- ---------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years)... 7.9 8.1 8.3
Expected volatility............ 26.91% 23.31% 23.45%
Expected dividend yield........ 5.09% 4.36% 5.00%
Risk-free interest rate........ 3.67% 4.60% 4.67%
Fair value per option............ $5.09 $6.45 $4.97
- ---------------------------------------------------------------------------
The effects of applying fair value accounting to FirstEnergy's stock
options would not materially affect the Company's net income.
(H) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. The Company records income taxes in accordance
with the liability method of accounting. Deferred income taxes reflect the net
tax effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for tax
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. Deferred income tax
liabilities related to tax and accounting basis differences and tax credit
carryforward items 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) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
FirstEnergy provides noncontributory defined benefit pension plans
that cover substantially all of the Company's employees. The trusteed plans
provide defined benefits based on years of service and compensation levels.
FirstEnergy's funding policy is based on actuarial computations using the
projected unit credit method. No pension contributions were required during the
three years ended December 31, 2003.
25
FirstEnergy 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 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.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions made to the plans, and earnings on plan assets. Such factors may
be further affected by business combinations (such as FirstEnergy's merger with
GPU, Inc. in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs may also be affected by
changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations and pension and OPEB costs. FirstEnergy uses a
December 31 measurement date for the majority of its plans.
Plan amendments to retirement health care benefits in 2003 and 2002,
relate to changes in benefits provided and cost-sharing provisions, which
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
On December 8, 2003, President Bush signed into law a bill that
expands Medicare, primarily adding a prescription drug benefit for
Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the
benefits it pays after 2006 will be lower as a result of the new Medicare
provisions. Due to uncertainties surrounding some of the new Medicare provisions
and a lack of authoritative accounting guidance about these issues, FirstEnergy
deferred the recognition of the impact of the new Medicare provisions as
provided by FASB Staff Position 106-1. The final accounting guidance could
require changes to previously reported information.
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Obligations and Funded Status Pension Benefits Other Benefits
---------------- --------------
As of December 31 2003 2002 2003 2002
------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at beginning of year.. $3,866 $3,548 $ 2,077 $ 1,582
Service cost............................. 66 59 43 28
Interest cost............................ 253 249 136 114
Plan participants' contributions......... -- -- 6 --
Plan amendments.......................... -- -- (123) (121)
Actuarial loss........................... 222 268 323 440
GPU acquisition.......................... -- (12) -- 110
Benefits paid............................ (245) (246) (94) (76)
------ ------ ------- -------
Benefit obligation at end of year........ $4,162 $3,866 $ 2,368 $ 2,077
====== ====== ======= =======
Change in fair value of plan assets
Fair value of plan assets at beginning
of year................................ $2,889 $3,484 $ 473 $ 535
Actual return on plan assets............. 671 (349) 88 (57)
Company contribution..................... -- -- 68 31
Plan participants' contribution.......... -- -- 2 --
Benefits paid............................ (245) (246) (94) (36)
------ ------ ------- -------
Fair value of plan assets at end of year. $3,315 $2,889 $ 537 $ 473
====== ====== ======= =======
Funded status............................ $ (847) $ (977) $(1,831) (1,604)
Unrecognized net actuarial loss.......... 919 1,186 994 752
Unrecognized prior service cost
(benefit).............................. 72 78 (221) (107)
Unrecognized net transition obligation... -- -- 83 92
------ ------ ------- -------
Net asset (liability) recognized......... $ 144 $ 287 $ (975) $ (867)
====== ====== ======= =======
Amounts Recognized in the
Consolidated Balance Sheets
As of December 31
Accrued benefit cost..................... $ (438) $ (548) $(975) $(867)
Intangible assets........................ 72 78 -- --
Accumulated other comprehensive loss..... 510 757 -- --
------ ------ ----- -----
Net amount recognized.................... $ 144 $ 287 $(975) $(867)
====== ====== ===== =====
Company's share of net amount recognized. $ 7 $ 19 $ (33) $ (56)
====== ====== ===== =====
26
Increase (decrease) in minimum liability
included in other comprehensive income
(net of tax).......................... $(145) $ 444 $ -- $ --
Weighted-Average Assumptions Used
to Determine Benefit Obligations
As of December 31
----------------------------------------
Discount rate........................... 6.25% 6.75% 6.25% 6.75%
Rate of compensation increase........... 3.50% 3.50%
Allocation of Plan Assets
As of December 31
-----------------------------------------
Asset Category
Equity securities....................... 70% 61% 71% 58%
Debt securities....................... 27 35 22 29
Real estate........................... 2 2 -- --
Other................................. 1 2 7 13
--- --- --- ---
Total................................. 100% 100% 100% 100%
=== === === ===
Information for Pension Plans With an
Accumulated Benefit Obligation in
Excess of Plan Assets 2003 2002
----------------------------------------- ---- ----
(In millions)
Projected benefit obligation............. $4,162 $3,866
Accumulated benefit obligation........... 3,753 3,438
Fair value of plan assets................ 3,315 2,889
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2003 were computed as follows:
Pension Benefits Other Benefits
---------------------- ---------------------
Components of Net Periodic Benefit Costs 2003 2002 2001 2003 2002 2001
---------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 66 $ 59 $ 35 $ 43 $ 29 $ 18
Interest cost........................... 253 249 133 137 114 65
Expected return on plan assets.......... (248) (346) (205) (43) (52) (10)
Amortization of prior service cost...... 9 9 9 (9) 3 3
Amortization of transition obligation
(asset)................................ -- -- (2) 9 9 9
Recognized net actuarial loss........... 62 -- -- 40 11 5
Voluntary early retirement program...... -- -- 6 -- -- 2
----- ----- ----- ----- ---- ----
Net periodic cost (income).............. $ 142 $ (29) $ (24) $ 177 $114 $ 92
===== ===== ===== ===== ==== ====
Company's share of net periodic cost
(income).............................. $ 5 $ 1 $ (1) $ 6 $ 4 $ 4
===== ===== ===== ===== ==== ====
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost
for Years Ended December 31
Discount rate.......................... 6.75% 7.25% 7.75% 6.75% 7.25% 7.75%
Expected long-term return on plan assets 9.00% 10.25% 10.25% 9.00% 10.25%
10.25%
Rate of compensation increase.......... 3.50% 4.00% 4.00%
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. The assumed rate of return on pension plan
assets considers historical market returns and economic forecasts for the types
of investments held by the Company's pension trusts. The long-term rate of
return is developed considering the portfolio's asset allocation strategy.
Assumed health care cost trend rates
As of December 31 2003 2002
- ------------------------------------------------------------------------------
Health care cost trend rate assumed for next
year (pre/post-Medicare).......................... 10%-12% 10%-12%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)................. 5% 5%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare).......................... 2009-2011 2008-2010
27
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:
1-Percentage- 1-Percentage-
Point Increase Point Decrease
- -------------------------------------------------------------------------------
(In millions)
Effect on total of service and interest cost.. $ 26 $ (19)
Effect on postretirement benefit obligation... $233 $(212)
FirstEnergy employs a total return investment approach whereby a mix
of equities and fixed income investments are used to maximize the long-term
return of plan assets for a prudent level of risk. Risk tolerance is established
through careful consideration of plan liabilities, plan funded status, and
corporate financial condition. The investment portfolio contains a diversified
blend of equity and fixed-income investments. Furthermore, equity investments
are diversified across U.S. and non-U.S. stocks, as well as growth, value, and
small and large capitalizations. Other assets such as real estate are used to
enhance long-term returns while improving portfolio diversification. Derivatives
may be used to gain market exposure in an efficient and timely manner; however,
derivatives are not used to leverage the portfolio beyond the market value of
the underlying investments. Investment risk is measured and monitored on a
continuing basis through periodic investment portfolio reviews, annual liability
measurements, and periodic asset/liability studies.
As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to the former GPU operating companies. Accordingly,
FirstEnergy requested an actuarial study to update the pension liabilities for
each of its subsidiaries. Based on the actuary's report, the accrued pension
costs for the Company as of June 30, 2003 decreased by $3 million. The
corresponding adjustment related to this change increased other comprehensive
income and deferred income taxes and decreased the payable to associated
companies.
Due to the increased market value of its pension plan assets, the
Company reduced its minimum liability as prescribed by SFAS 87 as of December
31, 2003 by $13 million, recording a decrease of $3 million in an intangible
asset and crediting OCI by $6 million (offsetting previously recorded deferred
tax benefits by $4 million). The remaining balance in OCI of $9 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $13
million as of December 31, 2003.
FirstEnergy does not expect to contribute to its pension plans in
2004 and expects to contribute $16 million to its other postretirement benefit
plans in 2004.
(J) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily ATSI, FirstEnergy Solutions
Corp. (FES) and FirstEnergy Service Company (FESC). The Ohio transition plan, as
discussed in the "Regulatory Matters" section, resulted in the corporate
separation of FirstEnergy's regulated and unregulated operations in 2001. FES
operates 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 are as follows:
2003 2002 2001
- -------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues from FES............... $103 $128 $181
Generating units rent from FES...... 15 14 14
Electric sales to CEI............... 109 104 97
Ground lease with ATSI.............. 2 2 2
Operating Expenses:
Purchased power under PSA........... 298 319 388
Transmission expenses............... 19 23 17
FESC support services............... 35 26 24
Other Income:
Interest income from ATSI........... 3 3 3
Interest income from FES............ 10 10 10
- -------------------------------------------------------------------------
28
FirstEnergy does not bill directly or allocate any of its costs to
any subsidiary company. Costs are allocated to the Company from FESC, a
subsidiary of FirstEnergy Corp. and a "mutual service company" as defined in
Rule 93 of the Public Utility Holding Company Act of 1935 (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; each company's proportionate amount of FirstEnergy's
aggregate direct payroll, number of employees, asset balances, revenues, number
of customers, other factors and specific departmental charge ratios. Management
believes that these allocation methods are reasonable. Intercompany transactions
with FirstEnergy and its other subsidiaries are generally settled under
commercial terms within thirty days, except for $65 million payable to
affiliates for pension and OPEB obligations.
The Company is selling 150 megawatts of its Beaver Valley Unit 2
leased capacity entitlement to CEI. Operating revenues for this transaction were
$109 million, $104 million and $97 million in 2003, 2002 and 2001, respectively.
This sale is expected to continue through the end of the lease period. (See Note
2.)
(K) CASH AND FINANCIAL INSTRUMENTS-
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. Cash and
cash equivalents included $2 million received in December 2003 which was
included in the NRG settlement claim sold in January 2004 (see Note 6) and $20
million used for the redemption of long-term debt in January 2003 as of December
31, 2003 and 2002, respectively. Noncash financing and investing activities
included capital lease transactions amounting to $1.0 million in 2001. There
were no capital lease transactions in 2003 and 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:
2003 2002
- ----------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- ----------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt....................................... $540 $564 $730 $772
Investments other than cash and cash equivalents:
Debt securities
- Maturity (5-10 years)........................... $124 $127 $123 $127
- Maturity (more than 10 years)................... 246 286 278 303
Equity securities................................. 2 2 2 2
All other......................................... 241 241 175 175
- ----------------------------------------------------------------------------------------------------------
$613 $656 $578 $607
==========================================================================================================
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 FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "All other" in the
table above) consist of equity securities ($145 million) and fixed income
securities ($96 million) as of December 31, 2003. Unrealized gains and losses
applicable to the Company's decommissioning trusts are recognized in the trust
investment with a corresponding offset to OCI, as fluctuations in the fair value
of the trusts will eventually affect earnings. Realized gains (losses) are
recognized as additions (reductions) to trust asset balances with an offset to
earnings. For 2003 and 2002, net realized losses were approximately $0.5
million, respectively, and $5.0 million and interest and dividend income totaled
approximately $6.7 million and $5.9 million, respectively.
Investments other than cash and cash equivalents in the table above
include available-for-sale securities, at fair value, with the following net
results:
29
2003* 2002*
- ---------------------------------------------------------------
(In millions)
Unrealized gains (losses)........... $ 32.8 $(10.0)
Proceeds from sales................. 147.2 143.5
Realized gains (losses)............. (0.5) (5.0)
- ---------------------------------------------------------------
* Includes the available-for-sale securities of the Company's
decommissioning trusts.
As of December 31, 2003 accumulated other comprehensive income (loss)
for available-for-sale securities consisted of investments with net unrealized
gains of $43.4 million and net unrealized losses of $8.7 million. The following
table provides details for the available-for-sale securities with net unrealized
losses as of December 31, 2003.
Less Than 12 Months 12 Months or More Total
-------------------- -------------------- ---------------------
Fair Unrealized Fair Unrealized Fair Unrealized
Security Type Value Losses Value Losses Value Losses
- -------------------------------------------------------------------------------------------------------
(In millions)
Equity Securities....... 5.7 1.7 8.1 6.9 13.8 8.6
Debt Securities......... 7.4 0.1 -- -- 7.4 0.1
- ----------------------------------------------------------------------------------------------------
Total............... 13.1 1.8 8.1 6.9 21.2 8.7
- ------------------------------------------------------------------------------------------------------
All of the aggregate unrealized losses related to available-for-sale
securities in the table above are considered to be temporary in nature. These
securities are primarily held by the Company's nuclear decommissioning trusts.
The Company has the ability and intent to hold these securities for the period
necessary to fund their cost.
(L) 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. Under SFAS 142, "Goodwill and Other Intangible Assets,"
amortization of existing goodwill ceased January 1, 2002. Instead, the Company
evaluates its goodwill for impairment at least annually and makes 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), the goodwill is tested for
impairment. When impairment is indicated, the Company would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill. The Company's annual review was completed in
the third quarter of 2003, with no impairment of goodwill indicated. The
forecasts used in the Company's evaluation of goodwill reflect operations
consistent with its general business assumptions. Unanticipated changes in those
assumptions could have a significant effect on its future evaluations of
goodwill. As of December 31, 2003, the Company had approximately $505 million of
goodwill. The impairment analysis includes a significant source of cash
representing the Company's recovery of transition costs as described above under
"Regulatory Matters." The Company does not believe that completion of transition
cost recovery will result in an impairment of goodwill.
The following table shows what net income would have been if goodwill
amortization had been excluded from prior periods:
2003 2002 2001
---- ---- ----
(In thousands)
Reported net income (loss)......... $45,480 $(5,142) $42,691
Add back goodwill amortization..... -- -- 14,032
------- ------- -------
Adjusted net income (loss)......... $45,480 $(5,142) $56,723
======= ======= =======
(M) CUMULATIVE EFFECT OF ACCOUNTING CHANGE-
Results for 2003 include an after-tax credit to net income of $25.6
million recorded by the Company upon adoption of SFAS 143 in January 2003. The
Company identified applicable legal obligations as defined under the new
accounting standard for nuclear power plant decommissioning and reclamation of a
sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS
143 in January 2003, asset retirement costs of $41.1 million were recorded as
part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $5.5 million. The asset retirement obligation
liability at the date of adoption was $172 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, the Company had recorded decommissioning
liabilities of $179.6 million. The cumulative effect adjustment for unrecognized
depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and the reversal of accumulated estimated removal
costs for non-regulated generation assets, was a $43.8 million increase to
income, or $25.6 million net of income taxes.
30
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, 2003 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, 2003 are
summarized as follows:
2003 2002 2001
- ---------------------------------------------------------------------------
(In millions)
Operating leases
Interest element............... $ 49.4 $ 52.6 $ 55.7
Other.......................... 62.4 58.6 52.4
Capital leases
Interest element............... -- -- 2.5
Other.......................... -- 0.3 14.1
- -------------------------------------------------------------------------
Total rentals.................. $111.8 $111.5 $124.7
=========================================================================
The future minimum lease payments as of December 31, 2003 are:
Operating Leases
------------------------------------
Lease Capital
Payments Trust Net
- ----------------------------------------------------------------------------
(In millions)
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
2008................................ 96.9 27.2 69.7
Years thereafter.................... 811.7 201.1 610.6
- ----------------------------------------------------------------------------
Total minimum lease payments........ $1,318.3 $326.8 $991.5
======== ====== ======
The Company has recorded above-market lease liabilities for Beaver
Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger
creating FirstEnergy. The total above-market lease obligation of $111 million
associated with Beaver Valley Unit 2 is being amortized on a straight-line basis
through the end of the lease term in 2017 (approximately $6 million per year).
The total above-market lease obligation of $298 million associated with the
Bruce Mansfield Plant is being amortized on a straight-line basis through the
end of 2016 (approximately $19 million per year). As of December 31, 2003 the
above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield
Plant totaled approximately $317 million, of which $25 million is current.
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
31
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 (Shippingport) arrangement effectively reduces lease
costs related to that transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for payment of cash
dividends on the Company's common stock.
(B) STOCK COMPENSATION PLANS-
FirstEnergy administers the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). 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. Several other stock compensation plans have been
acquired through the mergers with GPU and Centerior - GPU, Inc. Stock Option and
Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan), 1990 Stock Plan
for Employees of GPU, Inc. and Subsidiaries (GPU Plan) and Centerior Equity
Plan. No further stock-based compensation can be awarded under these plans.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2003 2002 2001
- ----------------------------------------------------------------------------
Restricted common shares granted...... -- 36,922 133,162
Weighted average market price ........ n/a (1) $36.04 $35.68
Weighted average vesting period
(years)............................. n/a (1) 3.2 3.7
Dividends restricted.................. n/a (1) Yes -- (2)
---------------------------------------------------------------------------
(1) Not applicable since no restricted stock was granted.
(2) 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, 2003, there were 410,399 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, 2001............... 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
Options granted...................... 3,981,100 29.71
Options exercised.................... 455,986 25.94
Options forfeited.................... 311,731 29.09
Balance, December 31, 2003............. 13,648,869 29.27
(1,919,662 options exercisable)........ 29.67
32
As of December 31, 2003, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
Options outstanding by plan and range of exercise price as of
December 31, 2003 were as follows:
Range of Options
FirstEnergy Program Exercise Prices Outstanding
- -----------------------------------------------------------------------
FE plan $19.31 - $29.87 9,904,861
$30.17 - $35.15 3,214,601
Plans acquired through merger:
GPU plan $23.75 - $35.92 501,734
Other plans 27,673
- ----------------------------------------------------------------------
Total 13,648,869
======================================================================
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 1(G) - "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 2003.
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
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)
- ---------------------------------------------
2004................................. $284
2005................................. 32
2006................................. --
2007................................. 30
2008................................. --
- ---------------------------------------------
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 $54 million and $32 million in 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 noncancelable municipal
bond insurance policies of $51 million to pay principal of, or interest on, the
pollution control revenue bonds.
The Company and CEI have unsecured letters of credit of approximately
$216 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).
33
(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, 2003, accumulated other comprehensive income consisted of a minimum
liability for unfunded retirement benefits of $(9.4) million and unrealized
gains on investments in securities available for sale of $21.1 million.
4. SHORT-TERM -BORROWINGS:
Short-term borrowings outstanding as of December 31, 2003, consisted
of $70 million of bank borrowings and $286 million from affiliates. The average
interest rate on short-term borrowings outstanding as of December 31, 2003 and
2002, were 1.8%.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$141 million for property additions and improvements from 2004-2006, of which
approximately $50 million is applicable to 2004. Investments for additional
nuclear fuel during the 2004-2006 period are estimated to be approximately $42
million, of which approximately $13 million applies to 2004. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $42 million and $21 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 $10.9 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 $89.0 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 $13.9 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. 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 that 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.
Overall, the Company believes it is in material compliance with existing
regulations but are unable to predict future change in regulatory policies and
what, if any, the effects of such change would be. In accordance with the Ohio
transition plan discussed in "Regulatory Matters" in Note 1(C), generation
operations and any related additional capital expenditures for environmental
compliance are the responsibility of FirstEnergy's competitive services business
unit.
Clean Air Act Compliance
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
34
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 is complying with SO2 reduction requirements under the
Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions required by the 1990 Amendments 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 (including Ohio and Pennsylvania) and the District of
Columbia 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 required
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. The Company's Pennsylvania
facilities complied with the NOx budgets in 2003 and all facilities will comply
with the NOx budgets in 2004 and thereafter.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone and proposed a new NAAQS for fine particulate
matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule"
covering a total of 29 states (including Ohio and Pennsylvania) and the District
of Columbia based on proposed findings that air pollution emissions from 29
eastern states and the District of Columbia significantly contribute to
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in
other states. The EPA has proposed the Interstate Air Quality Rule to
"cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase
II in 2015). According to the EPA, SO2 emissions would be reduced by
approximately 3.6 million tons in 2010, across states covered by the rule, with
reductions ultimately reaching more than 5.5 million tons annually. NOx emission
reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015. The future cost of compliance with these proposed regulations may be
substantial and will depend if and how they are ultimately implemented by the
states in which the Company operates affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants, identifying mercury as the hazardous air pollutant of greatest
concern. On December 15, 2003, the EPA proposed two different approaches to
reduce mercury emissions from coal-fired power plants. The first approach would
require plants to install controls known as "maximum achievable control
technologies" (MACT) based on the type of coal burned. According to the EPA, if
implemented, the MACT proposal would reduce nationwide mercury emissions from
coal-fired power plants by fourteen tons to approximately thirty-four tons per
year. The second approach proposes a cap-and-trade program that would reduce
mercury emissions in two distinct phases. Initially, mercury emissions would be
reduced by 2010 as a "co-benefits" from implementation of SO2 and NOx emission
caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the
mercury cap-and-trade program would be implemented in 2018 to cap nationwide
mercury emissions from coal-fired power plants at fifteen tons per year. The EPA
has agreed to choose between these two options and issue a final rule by
December 15, 2004. The future cost of compliance with these regulations may be
substantial.
Regulation of Hazardous Waste
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 subsequently determined that regulation of coal ash as a
hazardous waste is unnecessary. In April 2000, the EPA announced that it will
develop national standards regulating disposal of coal ash under its authority
to regulate nonhazardous waste.
The Company has been named as "potentially responsible parties"
(PRPs) 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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of December 31, 2003, 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, 2003. The Company accrues
35
environmental liabilities only when it can conclude that it is probable that it
has an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in the Company's determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.
Climate Change
In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but it failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.
The Company cannot currently estimate the financial impact of climate
change policies although the potential restrictions on carbon dioxide (CO2)
emissions could require significant capital and other expenditures. However, the
CO2 emissions per kilowatt-hour of electricity generated by the Company is lower
than many regional competitors due to the Company's diversified generation
sources which includes low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the
result of the federal Clean Water Act and its amendments, apply to the
Companies' plants. In addition, Ohio and Pennsylvania have water quality
standards applicable to the Companies' operations. As provided in the Clean
Water Act, authority to grant federal National Pollutant Discharge Elimination
System water discharge permits can be assumed by a state. Ohio and Pennsylvania
have assumed such authority.
(D) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against FirstEnergy and its subsidiaries.
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. FirstEnergy continues to
accumulate data and evaluate the status of its electrical system prior to and
during the outage event, and continues to cooperate with the U.S.-Canada Power
System Outage Task Force (Task Force) investigating the August 14th outage. The
interim report issued by the Task Force on November 18, 2003 concluded that the
problems leading to the outage began in FirstEnergy's service area.
Specifically, the interim report concludes, among other things, that the
initiation of the August 14th outage resulted from the coincidence on that
afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest Independent System Operator and PJM
Interconnection) to provide effective diagnostic support. FirstEnergy believes
that that the interim report does not provide a complete and comprehensive
picture of the conditions that contributed to the August 14th outage and that it
does not adequately address the underlying causes of the outage. FirstEnergy
remains convinced that the outage cannot be explained by events on any one
utility's system. On November 25, 2003, the PUCO ordered FirstEnergy to file a
plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy
will correct problems identified by the Task Force as events contributing to the
August 14th outage and addressing how FirstEnergy proposes to upgrade its
control room computer hardware and software and improve the training of control
room operators to ensure that similar problems do not occur in the future. The
PUCO, in consultation with the North American Electric Reliability Council, will
review the plan before determining the next steps in the proceeding. On December
24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part
of Ohio's power grid. The study is to examine the stability of the grid in
critical points in the Cleveland and Akron areas; the status of projected power
reserves during summer 2004 through 2008; and the need for new transmission
lines or other grid projects. The FERC ordered the study to be completed within
120 days. At this time, it is unknown what the cost of such study will be, or
the impact of the results.
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. NRG filed voluntary bankruptcy petitions in May 2003; subsequently,
FirstEnergy reached an agreement for settlement of its claim against NRG.
FirstEnergy sold its entire claim for $170 million (Company's share - $12
million) in January 2004.
36
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. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. As required,
the Company adopted FIN 46R for interests in VIEs or potential VIEs commonly
referred to as special-purpose entities effective December 31, 2003. The Company
will adopt FIN 46R for all other types of entities effective March 31, 2004.
The Company currently has transactions with entities in connection
with sale and leaseback arrangements which fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN
46R. In 1997, the Company and CEI, an affiliated company, established
Shippingport to purchase all of the lease obligation bonds issued by the owner
trusts in the Bruce Mansfield Plant sale and leaseback transactions. Prior to
the adoption of FIN 46R, the assets and liabilities of the trust were included
on a proportionate basis in the financial statements of the Company and CEI.
Upon adoption of FIN 46R, CEI was determined to be the primary beneficiary of
Shippingport, and therefore consolidated the entire trust as of December 31,
2003. This changed our Shippingport investment of $220 million to an investment
in collateralized lease bonds of $210 million ($9 million current). The $10
million difference represents the minority interest included on the financial
statements of CEI.
In reviewing the sale and leaseback arrangements, the Company also
evaluated its interest in the owner trusts that acquired interests in the Bruce
Mansfield Plant. The Company was determined not to be the primary beneficiary of
any of these owner trusts and was therefore not required to consolidate these
entities. The leases are accounted for as operating leases in accordance with
GAAP and their related obligations are disclosed in Note 2.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, the company implemented SFAS 143 which provides
accounting standards for retirement obligations associated with tangible
long-lived assets. This statement requires recognition of the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. See Notes 1(F) and 1(M) for further discussions of SFAS 143.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary
Impairment and its Application to Certain Investments"
In November 2003, the EITF reached consensus that certain
quantitative and qualitative disclosures are required for debt and equity
securities classified as available-for-sale or held-to-maturity. The guidance
requires the disclosure of the aggregate amount of unrealized losses and the
aggregate related fair value for investments with unrealized losses that have
not been recognized as other-than-temporary impairments. The Company has adopted
the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See
Note 1(K)).
8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The quarterly financial information for the first three quarters of
2003 have been restated to correct the amounts reported for operating expense
and interest charges. Costs that should have been capitalized to construction
projects were improperly recorded as operating expenses of $0.2 million, $0.3
million and $0.7 million in the first, second and third quarters, respectively.
In addition, interest expense was overstated by $0.6 million in the first
quarter and $0.2 million in each of the second and third quarters. These
corrections have resulted in restated earnings increases of $0.8 million, $0.5
million and $0.9 million during the quarters ended March 31, 2003, June 30, 2003
and September 30, 2003, respectively.The impact of these adjustments was not
material to the Company's consolidated balance sheets or consolidated statements
of cash flows for any quarter of 2003. The following summarizes certain
consolidated operating results by quarter for 2003 and 2002.
37
Three Months Ended March 31, 2003 June 30, 2003 September 30, 2003 December 31, 2003
- ----------------------------------------------------------------------------------------------------------------------
As Previously As As Previously As As Previously As
Reported Restated Reported Restated Reported Restated
-------- -------- -------- -------- -------- --------
(In millions)
Operating Revenues............. $231.8 $231.8 $216.0 $216.0 $260.2 $260.2 $224.8
Operating Expenses and Taxes... 226.3 226.7 218.1 217.9 242.0 241.5 212.7
- -----------------------------------------------------------------------------------------------------------------
Operating Income (Loss)........ 5.5 5.1 (2.1) (1.9) 18.2 18.7 12.1
Other Income .................. 3.1 3.3 3.8 3.8 5.8 5.8 9.3
Net Interest Charges........... 10.0 9.1 11.4 11.1 8.2 7.9 8.2
- ----------------------------------------------------------------------------------------------------------------
Income (Loss) Before Cumulative
Effect of Accounting Change.. (1.4) (0.7) (9.7) (9.2) 15.8 16.6 13.2
Cumulative Effect of Accounting
Change (Net of Income Taxes). 25.6 25.6 -- -- -- -- --
- ----------------------------------------------------------------------------------------------------------------
Net Income (Loss).............. $ 24.2 $ 24.9 $ (9.7) $ (9.2) $ 15.8 $ 16.6 $ 13.2
=================================================================================================================
Earnings (Loss) Applicable
To Common Stock............. $ 21.9 $ 22.7 $(11.9) $(11.4) $ 13.5 $ 14.4 $ 11.0
=================================================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
- ----------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $252.6 $250.3 $269.9 $223.3
Operating Expenses and Taxes................ 241.9 222.7 251.7 243.1
- ----------------------------------------------------------------------------------------------------------------
Operating Income (Loss)..................... 10.7 27.6 18.2 (19.8)
Other Income ............................... 4.3 3.7 4.0 1.2
Net Interest Charges........................ 14.7 14.9 14.5 11.1
- ----------------------------------------------------------------------------------------------------------------
Net Income (Loss)........................... $ 0.3 $ 16.4 $ 7.7 $(29.7)
================================================================================================================
Earnings (Loss) Applicable to
Common Stock............................. $ (4.4) $ 14.3 $ 5.5 $(31.4)
================================================================================================================
38
Report of Independent Auditors
To the Stockholders and Board of Directors of The Toledo Edison Company:
In our opinion, the accompanying consolidated balance sheets and consolidated
statements of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of The Toledo Edison
Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of
December 31, 2003 and 2002 and the results of their operations and their cash
flows for each of the three yeas in the period ended December 31, 2003 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 audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 1(L) to the consolidated financial statements, the Company
changed its method of accounting for goodwill as of January 1, 2002. As
discussed in Note 1(F) to the consolidated financial statements, the Company
changed its method of accounting for asset retirement obligations as January 1,
2003. As discussed in Note 7 to the consolidated financial statements, the
Company changed its method of accounting for the consolidation of variable
interest entities as of December 31, 2003.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 25, 2004
39