THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
2003 ANNUAL REPORT TO STOCKHOLDERS
The Cleveland Electric Illuminating Company 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
1,700 square miles in northeastern Ohio. It also engages in the sale, purchase
and interchange of electric energy with other electric companies. The area it
serves has a population of approximately 1.9 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................... 21-39
Report of Independent Auditors............................... 40
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
SELECTED FINANCIAL DATA
2003 2002 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues...................... $1,720,784 $1,843,671 $2,064,622 $1,890,339 $1,864,954
========== ========== ========== ========== ==========
Operating Income........................ $ 255,148 $ 306,152 $ 354,422 $ 397,568 $ 405,640
========== ========== ========== ========== ==========
Income Before Cumulative Effect
of Accounting Change................. $ 197,033 $ 136,952 $ 177,905 $ 210,424 $ 204,963
========== ========== ========== ========== ==========
Net Income.............................. $ 239,411 $ 136,952 $ 177,905 $ 210,424 $ 204,963
========== ========== ========== ========== ==========
Earnings on Common Stock................ $ 231,885 $ 121,262 $ 153,067 $ 189,581 $ 171,439
========== ========== ========== ========== ==========
Total Assets............................ $6,773,448 $6,510,243 $6,526,596 $6,756,921 $6,189,261
========== ========== ========== ========== ==========
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder's Equity............. $1,778,827 $1,200,001 $1,082,041 $1,095,874 $ 990,177
Preferred Stock-
Not Subject to Mandatory Redemption.. 96,404 96,404 141,475 238,325 238,325
Subject to Mandatory Redemption...... -- 105,021 106,288 26,105 116,246
Long-Term Debt.......................... 1,884,643 1,975,001 2,156,322 2,634,692 2,682,795
---------- ---------- ---------- ---------- ----------
Total Capitalization.................... $3,759,874 $3,376,427 $3,486,126 $3,994,996 $4,027,543
========== ========== ========== ========== ==========
CAPITALIZATION RATIOS:
Common Stockholder's Equity............. 47.3% 35.5% 31.0% 27.4% 24.6%
Preferred Stock-
Not Subject to Mandatory Redemption.. 2.6 2.9 4.1 6.0 5.9
Subject to Mandatory Redemption...... -- 3.1 3.0 0.6 2.9
Long-Term Debt.......................... 50.1 58.5 61.9 66.0 66.6
----- ----- ----- ----- -----
Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
DISTRIBUTION KILOWATT-HOUR
DELIVERIES (Millions):
Residential............................. 5,216 5,370 5,061 5,061 5,278
Commercial.............................. 4,690 4,628 4,907 6,656 6,509
Industrial.............................. 8,908 8,921 9,593 8,320 8,069
Other................................... 169 167 166 167 166
------ ------ ------ ------ ------
Total................................... 18,983 19,086 19,727 20,204 20,022
====== ====== ====== ====== ======
CUSTOMERS SERVED:
Residential............................. 669,337 677,095 673,852 667,115 667,954
Commercial.............................. 80,596 71,893 70,636 69,103 69,954
Industrial.............................. 2,318 4,725 4,783 4,851 5,090
Other................................... 286 289 292 307 223
------- ------- ------- ------- -------
Total................................... 752,537 754,002 749,563 741,376 743,221
======= ======= ======= ======= =======
Number of Employees..................... 949 974 1,025 1,046 1,694
1
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), adverse
regulatory or legal decisions and the outcome of governmental investigations,
availability and cost of capital, the continuing availability and o peration 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 Spring 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
being recovered under 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 and reclassifications
on 2002 financial results.
Results of Operations
- ---------------------
Earnings on common stock in 2003 increased 91.2% to $231.9 million
from $121.3 million in 2002. The increase in earnings in 2003 was due primarily
to a gain of $74.7 million, net of tax, representing net proceeds from the
settlement of our claim against NRG Energy, Inc. relating to the terminated sale
of three of our fossil power plants (see Note 6). Also contributing to the
increase in earnings was a $42.4 million gain from the cumulative effect of
adopting Statement of Financial Accounting Standards (SFAS) 143, "Accounting for
Asset Retirement Obligations." Excluding these gains, earnings on common stock
decreased $6.4 million or 5%, in 2003. The decrease resulted primarily from
lower operating revenues, which were partially offset by lower operating
expenses, net interest charges and preferred stock dividend requirements.
Earnings on common stock in 2002 decreased 20.8% to $121.3 million in 2002 from
$153.1 million in 2001. The earnings decrease in 2002 primarily resulted from
lower operating revenues, which was partially offset by lower operating
expenses, net interest charges and preferred stock dividend requirements.
Operating revenues decreased $122.9 million or 6.7% in 2003 compared
with 2002. The lower revenues were due to milder weather and increased sales by
alternative suppliers. Kilowatt-hour sales to retail customers declined by 13.6%
in 2003 from the prior year, with declines in all customer sectors (residential,
commercial and industrial), resulting in a $56.0 million reduction in generation
sales revenue. Kilowatt-hour sales of electricity by alternative suppliers in
our franchise area increased by 9 percentage points in 2003 from last year.
Further decreasing operating revenues were Ohio transition plan incentives,
provided to customers to encourage switching to alternative energy providers -
$30.1 million of additional credits were provided to customers in 2003 compared
with 2002. These revenue reductions are deferred for future recovery under our
transition plan and do not materially affect current period earnings. Sales
revenues from wholesale customers (primarily FirstEnergy Solutions (FES), an
affiliated company) decreased by $25.8 million in 2003 compared with 2002. The
lower sales resulted from reductions in available nuclear generation of 17.2% in
2003 compared to 2002. Available generation decreased due to the extended outage
of Davis-Besse and generating capacity removed from service due to additional
nuclear refueling activities in 2003 compared to 2002.
Operating revenues decreased $221.0 million or 10.7% in 2002 compared
with 2001. The lower revenues reflected the effects of a sluggish national
economy on our service area, shopping by Ohio customers for alternative energy
providers and decreases in wholesale revenues. Retail kilowatt-hour sales
declined by 23.9% in 2002 from the prior year, with declines in all customer
sectors (residential, commercial and industrial), resulting in a $123.0 million
reduction in generation sales revenue. Our lower generation kilowatt-hour sales
resulted primarily from customer choice in Ohio. Sales of electric generation by
alternative suppliers as a percent of total sales delivered in our franchise
area
2
increased to 31.5% in 2002 from 12.9% in 2001, while our share of electric
generation sales in our franchise areas decreased by 18.6% compared to the prior
year. Distribution deliveries decreased 3.3% in 2002 compared with 2001, which
decreased revenues from electricity throughput by $18.9 million in 2002 from the
prior year. The lower distribution deliveries resulted from the effect that
continued sluggishness in the economy had on demand by commercial and industrial
customers which was offset in part by the additional residential demand due to
warmer summer weather. Customer shopping incentives further reduced operating
revenues $43.4 million in 2002 from the prior year. Sales revenues from
wholesale customers decreased by $43.8 million in 2002 compared to 2001, due to
lower kilowatt-hour sales. The reduced kilowatt-hour sales resulted from lower
sales to FES, reflecting the extended outage at Davis-Besse.
Changes in electric generation sales and distribution deliveries in
2003 and 2002, compared to the prior year, are summarized in the following
table:
Changes in KWH Sales 2003 2002
---------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (13.6)% (23.9)%
Wholesale............................. (12.4)% (12.8)%
- ----------------------------------------------------------------------
Total Electric Generation Sales......... (13.0)% (18.9)%
=====================================================================
Distribution Deliveries:
Residential........................... (2.9)% 6.1%
Commercial and industrial............. 0.4% (6.6)%
- ----------------------------------------------------------------------
Total Distribution Deliveries........... (0.5)% (3.3)%
=====================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $71.9 million in 2003
and by $172.7 million in 2002 from 2001. 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..................... $ 8.2 $(181.2)
Nuclear operating costs...................... 33.7 98.7
Other operating costs........................ (42.9) 16.5
--------------------------------------------------------------------
Total operation and maintenance expenses... (1.0) (66.0)
Provision for depreciation and amortization.. (46.4) (59.7)
General taxes................................ (11.4) 2.9
Income taxes................................. (13.1) (49.9)
---------------------------------------------------------------------
Total operating expenses and taxes......... $(71.9) $(172.7)
- -----------------------------------------------------------------------
Higher fuel and purchased power costs in 2003 resulted from an
increase in purchased power costs partially offset by lower fuel costs from
reduced nuclear generation. Higher purchased power costs primarily reflect
increased unit costs partially offset by lower power purchases from FES in 2003
compared to 2002. Increased nuclear costs resulted from unplanned work performed
during the Perry Plant's 56-day nuclear refueling outage (44.85% ownership) in
the Spring of 2003, and the Beaver Valley Unit 2 28-day refueling outage (24.47%
ownership) in the third quarter of 2003, compared with the 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 resulted from a $177.0
million reduction in power purchased from FES, reflecting lower kilowatt-hours
purchased due to reduced kilowatt-hour sales and lower unit prices. Nuclear
operating costs increased $98.7 million in 2002, primarily due to approximately
$59.1 million of incremental Davis-Besse maintenance costs related to its
extended outage (see Davis-Besse Restoration). The $16.5 million increase in
other operating costs resulted principally from higher employee benefit costs.
The decrease in depreciation and amortization charges in 2003 was
primarily attributable to several factors - higher shopping incentive deferrals
($30.1 million), lower charges following the implementation of SFAS 143 ($17.5
million) and lower fossil plant depreciation ($13.6 million) - partially offset
by higher transition plan amortization ($17.7 million).
Charges for depreciation and amortization decreased by $59.7 million
in 2002 from 2001 primarily due to higher shopping incentive deferrals and
tax-related deferrals under our transition plan, and the cessation of goodwill
amortization.
3
General taxes decreased $11.4 million in 2003 from 2002 principally
due to settled property tax claims.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $29.3
million in 2003 and by $4.6 million in 2002 due to our debt paydown program. Our
redemption and refinancing activities during 2003 totaled $416 million and $194
million, respectively, and are expected to result in annualized savings of
approximately $39 million.
Cumulative Effect of Accounting Changes
Results for 2003 include an after-tax credit to net income of $42.4
million recorded upon adoption of SFAS 143 in January 2003. We identified
applicable legal obligations as defined under the new accounting standard for
nuclear power plant decommissioning, reclamation of a sludge disposal pond at
the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a
result of adopting SFAS 143, asset retirement costs of $49.9 million were
recorded as part of the carrying amount of the related long-lived asset, offset
by accumulated depreciation of $6.8 million. The asset retirement obligation
(ARO) liability at the date of adoption was $238.3 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 $242.5 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 $72.5 million increase to
income, or $42.4 million net of income taxes.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements were $8.2 million lower in
2003, compared to the prior year principally due to optional redemptions of
preferred stock in 2002. The redemption resulted in a decrease of $9.1 million
in 2002. Premiums related to the optional redemptions partially offset the lower
dividend requirements.
Capital Resources and Liquidity
- -------------------------------
Through net debt and preferred stock redemptions, we continued to
reduce the cost of debt and preferred stock, and improve our financial position
in 2003. During 2003, we reduced our total outstanding debt by approximately
$490 million, partially funded by a $300 million equity contribution from
FirstEnergy. As a result, our common stockholder's equity as a percentage of
total capitalization increased to 47% as of December 31, 2003 from 21% at the
end of 1997. Over the last six years, we have reduced the average cost of
outstanding debt from 8.15% in 1997 to 6.56% in 2003.
Changes in Cash Position
As of December 31, 2003, we had $24.8 million of cash and cash
equivalents, compared with $30.4 million as of December 31, 2002. Cash and cash
equivalents included $25 million received in December 2003 which was included in
the NRG settlement claim sold in January 2004 (see Note 6) and $30 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
Our consolidated net cash from operating activities is provided by
our regulated energy services. Net cash provided from operating activities was
$364.8 million in 2003, $317.2 million in 2002 and $365.5 million in 2001. Cash
flows provided from operating activities are as follows:
Operating Cash Flows 2003 2002 2001
------------------------------------------------------------------------
(In millions)
Cash earnings (1)............. $309.4 $326.5 $ 467.6
Working capital and other..... 55.4 (9.3) (102.1)
------------------------------------------------------------------------
Total................... $364.8 $317.2 $365.5
========================================================================
(1) Includes net income, depreciation and amortization,
deferred operating lease costs, deferred income taxes,
investment tax credits and major noncash charges.
Net cash from operating activities increased $48 million in 2003 compared
to 2002 as a result of a $65 million reduction in working capital and other
requirements partially offset by a $17 million reduction in cash earnings. The
largest factor contributing to the working capital and other decrease was an $80
million increase in accrued taxes.
4
Cash Flows from Financing Activities
In 2003, the net cash used for financing activities of $197.9 million
primarily reflects the redemptions of debt and preferred stock shown below.
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................... -- $107.0
Unsecured Notes........................... $296.9 --
----------------------------------------------------------------------------
Short-term Borrowings, Net..................... $ -- $190.9
============================================================================
Redemptions
-----------
First Mortgage Bonds...................... 550.0 195.0
Pollution Control Notes................... 111.7 78.7
Secured Notes............................. 15.0 33.0
Preferred Stock........................... 1.1 164.7
Other..................................... 0.4 2.8
---------------------------------------------------------------------------
678.2 474.2
Short-term Borrowings, Net..................... $109.2 $ --
===========================================================================
We had about $25.3 million of cash and temporary investments and
approximately $188.2 million of short-term indebtedness at the end of 2003. We
had the capability to issue approximately $1.1 billion of additional first
mortgage bonds (FMB) on the basis of property additions and retired bonds,
although unsecured senior note indentures entered into by the Company in 2003
limit our ability to issue secured debt, including FMBs, subject to certain
exceptions. We have no restrictions on the issuance of preferred stock. At the
end of 2003, our common equity as a percentage of capitalization, including debt
relating to assets held for sale, stood at 47% compared to 36% at the end of
2002.
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 amount, 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-
CEI 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 CEI. 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-". CEI's ratings were lowered one notch as well. The ratings were removed
from CreditWatch with negative implications, where
5
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.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2. Ratings of the Company were confirmed. Moody's said that
FirstEnergy's 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 in investing activities totaled $172.5 million in 2003.
The net cash used for investing resulted from property additions, which was
offset in part by a reduction of the investment in collateralized lease bonds.
Expenditures for property additions primarily include expenditures supporting
our distribution of electricity and capital expenditures related to Davis-Besse
(see Davis-Besse Restoration).
Our cash requirements in 2004 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Over the next three years, we expect to meet our contractual
obligations with cash from operations. Thereafter, we expect to use a
combination of cash from operations and funds from the capital markets.
Contractual Obligations
- -----------------------
Our cash contractual obligations as of December 31, 2003 that we
consider firm obligations are as follows:
Contractual Obligations Total 2004 2005-2006 2007-2008 Thereafter
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt.................. $2,234 $288 $ 22 $269 $1,655
Short-term borrowings........... 188 188 -- -- --
Preferred stock (1)............. 5 1 2 2 --
Capital leases (2).............. 9 1 2 2 4
Operating leases (2)............ 202 27 33 21 121
Purchases (3) .................. 505 66 142 113 184
- --------------------------------------------------------------------------------------------------------------
Total...................... $3,143 $571 $201 $407 $1,964
==============================================================================================================
<FN>
(1) Subject to mandatory redemption.
(2) Operating lease payments are net of capital trust receipts of $574.6 million
(see Note 2).
(3) Fuel and power purchases under contracts with fixed or minimum
quantities and approximate timing.
</FN>
Our capital spending for the period 2004-2006 is expected to be about
$275 million (excluding nuclear fuel) of which approximately $92 million applies
to 2004. Investments for additional nuclear fuel during the 2004-2006 period are
estimated to be approximately $61 million, of which about $29 million relates to
2004. During the same periods, our nuclear fuel investments are expected to be
reduced by approximately $60 million and $30 million, respectively, as the
nuclear fuel is consumed.
Off-Balance Sheet Arrangements
Obligations not included on our Consolidated Balance Sheet primarily
consist of a sale and leaseback arrangement involving the Bruce Mansfield Plant,
which is reflected in the operating lease payments disclosed above (see Note 2 -
Leases). The present value of these sale and leaseback operating lease
commitments, net of trust investments, was $134 million as of December 31, 2003.
We sell substantially all of our retail customer receivables, which provided
$112 million of off-balance sheet financing as of December 31, 2003.
6
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced
since a significant portion of our debt has fixed interest rates, as noted in
the following table.
The table below presents principal amounts and related weighted
average interest rates by year of maturity for our investment portfolio, debt
obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value
- -------------------------------------------------------------------------------------------------------------------
There- Fair
Year of Maturity 2004 2005 2006 2007 2008 after Total Value
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income............... $ 10 $44 $45 $ 36 $ 38 $ 665 $ 838 $ 952
Average interest rate...... 7.7% 7.9% 7.8% 7.7% 7.7% 7.1% 7.3%
____________________________________________________________________________________________________________________
Liabilities
- --------------------------------------------------------------------------------------------------------------------
Long-term Debt and Other
Long-Term Obligations:
Fixed rate.................... $288 $10 $12 $129 $140 $1,437 $2,016 $2,226
Average interest rate ..... 7.7% 7.7% 7.7% 7.2% 6.9% 7.1% 7.2%
Variable rate................. $ 218 $ 218 $ 218
Average interest rate...... 1.7% 1.8%
Preferred Stock Subject to
Mandatory Redemption....... $ 1 $ 1 $ 1 $ 1 $ 1 $ 5 $ 5
Average dividend rate...... 7.4% 7.4% 7.4% 7.4% 7.4% 7.4%
Short-term Borrowings......... $188 $ 188 $ 188
Average interest rate...... 2.2% 2.2%
- -------------------------------------------------------------------------------------------------------------------
Equity Price Risk
- -----------------
Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $188
million and $120 million as of December 31, 2003 and 2002, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$19 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 were $
1.1 billion and $1.2 billion, 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 400 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.
7
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 2008
to July 2009;
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.
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
8
service contributed to S&P's reduction in our credit rating in the fourth
quarter of 2003 (see Cash Flows from Financing Activities).
Incremental costs associated with the extended Davis-Besse outage
(CEI's share - 51.38%) 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 Company's Ohio and
Pennsylvania facilities. Various regulatory 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 $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
9
per kilowatt-hour of electricity generated by the Company is lower
than many regional competitors due to the Company's diversified generation
sources which include non-CO2 emitting 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 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.
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 - $1.1 billion 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
10
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.
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 $17 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 $12 million, recording a decrease of $4 million in an intangible asset and
crediting OCI by $5 million (offsetting previously recorded deferred tax
benefits by $3 million). The remaining balance in OCI of $25 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 $33
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:
11
Increase in Costs from Adverse Changes in Key Assumptions
- ------------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
- ------------------------------------------------------------------------------
(In millions)
Discount rate................ Decrease by 0.25% $ 10 $ 5 $ 15
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 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 $1.7 billion of goodwill.
Nuclear Decommissioning
In accordance with SFAS No. 143, we recognize an 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
12
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, the
Company and The Toledo Edison Company (TE), 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 the Company and TE. Upon adoption of FIN 46R, we were determined
to be the primary beneficiary of Shippingport, and therefore consolidated the
entire trust as of December 31, 2003. As a result, Shippingport's note payable
to TE of approximately $208 million ($9 million current) is recognized as
long-term debt on our Consolidated Balance Sheets.
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.
As described in Note 3(F), we created a statutory business trust to
issue trust preferred securities in the amount of $100 million. Application of
the guidance in FIN 46R resulted in the holders of the preferred securities
being considered the primary beneficiaries of these trusts. Therefore, we have
deconsolidated the trust and recognized an equity investment in the trust of $3
million and subordinated debentures to the trust of $103 million as of December
31, 2003.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003 for
all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, we reclassified as
debt the preferred stock subject to mandatory redemption with a carrying value
of approximately $5 million as of December 31, 2003. Dividends on preferred
stock subject to mandatory redemption on our Consolidated Statements of Income,
which were not included in net interest charges prior to the adoption of SFAS
150, are now included in net interest charges for the six months ended December
31, 2003.
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.
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 CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (Note 1(J)).............................. $1,720,784 $1,843,671 $2,064,622
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1(J))..................... 595,279 587,108 768,306
Nuclear operating costs (Note 1(J))...................... 240,971 207,313 108,587
Other operating costs (Note 1(J))........................ 236,408 279,242 262,745
---------- ---------- ----------
Total operation and maintenance expenses............... 1,072,658 1,073,663 1,139,638
Provision for depreciation and amortization.............. 198,307 244,727 304,417
General taxes............................................ 136,434 147,804 144,948
Income taxes............................................. 58,237 71,325 121,197
---------- ---------- ----------
Total operating expenses and taxes..................... 1,465,636 1,537,519 1,710,200
---------- ---------- ----------
OPERATING INCOME............................................ 255,148 306,152 354,422
OTHER INCOME (Note 6)....................................... 97,785 15,971 13,292
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES.......................... 352,933 322,123 367,714
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................... 157,967 179,140 191,695
Allowance for borrowed funds used during
construction........................................... (8,232) (4,331) (2,293)
Other interest expense................................... 1,665 1,462 32
Subsidiary's preferred stock dividend requirements....... 4,500 8,900 375
---------- ---------- ----------
Net interest charges..................................... 155,900 185,171 189,809
---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE..................................... 197,033 136,952 177,905
Cumulative effect of accounting change (net of income
taxes of $30,168,000) (Note 1(M))........................ 42,378 -- --
---------- ---------- ----------
NET INCOME.................................................. 239,411 136,952 177,905
PREFERRED STOCK DIVIDEND
REQUIREMENTS............................................. 7,526 15,690 24,838
---------- ---------- ----------
EARNINGS ON COMMON STOCK.................................... $ 231,885 $ 121,262 $ 153,067
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
</FN>
14
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $4,232,335 $4,045,465
Less-Accumulated provision for depreciation.................................... 1,857,588 1,778,085
---------- ----------
2,374,747 2,267,380
---------- ----------
Construction work in progress-
Electric plant............................................................... 159,897 153,104
Nuclear fuel................................................................. 21,338 45,354
---------- ----------
181,235 198,458
---------- ----------
2,555,982 2,465,838
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 2)............................................ 605,915 435,907
Nuclear plant decommissioning trusts........................................... 313,621 230,527
Long-term notes receivable from associated companies........................... 107,946 102,978
Other.......................................................................... 23,636 21,004
---------- ----------
1,051,118 790,416
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 24,782 30,382
Receivables-
Customers.................................................................... 10,313 11,317
Associated companies......................................................... 40,541 74,002
Other (less accumulated provisions of $1,765,000 and $1,015,000,
respectively, for uncollectible accounts).................................. 185,179 134,375
Notes receivable from associated companies..................................... 482 447
Materials and supplies, at average cost-
Owned........................................................................ 50,616 18,293
Under consignment............................................................ -- 38,094
Prepayments and other.......................................................... 4,511 4,217
---------- ----------
316,424 311,127
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 1,056,050 1,145,005
Goodwill....................................................................... 1,693,629 1,693,629
Property taxes................................................................. 77,122 79,430
Other.......................................................................... 23,123 24,798
---------- ----------
2,849,924 2,942,862
---------- ----------
$6,773,448 $6,510,243
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $1,778,827 $1,200,001
Preferred stock-
Not subject to mandatory redemption.......................................... 96,404 96,404
Subject to mandatory redemption (Note 3(E)).................................. -- 5,021
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures (Note 7)..... -- 100,000
Long-term debt and other long-term obligations-
Preferred stock subject to mandatory redemption (Note 3(E)).................. 4,014 --
Subordinated debentures to affiliated trusts................................. 103,093 --
Notes payable to associated companies........................................ 198,843 --
Other........................................................................ 1,578,693 1,975,001
---------- ----------
3,759,874 3,376,427
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock........................... 387,414 388,190
Accounts payable-
Associated companies......................................................... 245,815 267,664
Other........................................................................ 7,342 14,583
Notes payable to associated companies.......................................... 188,156 288,583
Accrued taxes................................................................. 202,522 126,261
Accrued interest............................................................... 37,872 51,767
Lease market valuation liability............................................... 60,200 60,200
Other.......................................................................... 76,722 64,624
---------- ----------
1,206,043 1,261,872
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 486,048 407,297
Accumulated deferred investment tax credits.................................... 65,996 70,803
Nuclear plant decommissioning costs............................................ -- 242,511
Asset retirement obligation.................................................... 254,834 --
Retirement benefits............................................................ 105,101 171,968
Lease market valuation liability............................................... 728,400 788,600
Other.......................................................................... 167,152 190,765
---------- ----------
1,807,531 1,871,944
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)................................................................
---------- ----------
$6,773,448 $6,510,243
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
</FN>
15
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 105,000,000 shares
79,590,689 shares outstanding.................................................... $1,281,962 $ 981,962
Accumulated other comprehensive income (loss) (Note 3(G)).......................... 2,653 (44,284)
Retained earnings (Note 3(A))...................................................... 494,212 262,323
---------- ----------
Total common stockholder's equity................................................ 1,778,827 1,200,001
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- ---------------------
2003 2002 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (NOTE 3(C)):
Cumulative, without par value-
Authorized 4,000,000 shares
Not Subject to Mandatory Redemption:
$ 7.40 Series A................... 500,000 500,000 $101.00 $50,500 50,000 50,000
Adjustable Series L................ 474,000 474,000 100.00 47,400 46,404 46,404
--------- --------- ------- ---------- ----------
Total Not Subject to Mandatory
Redemption......................... 974,000 974,000 $97,900 96,404 96,404
========= ========= ======= ---------- ----------
Subject to Mandatory Redemption
(Note 3(E)):
$ 7.35 Series C**................. -- 60,000 -- 6,021
Redemption Within One Year**......... -- (1,000)
--------- --------- ---------- ----------
Total Subject to Mandatory
Redemption -- 60,000 -- 5,021
========= ========= ---------- ----------
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY COMPANY SUBORDINATED
DEBENTURES (Note 3(F)):
Cumulative, $25 stated value-
Authorized 4,000,000 shares
Subject to Mandatory Redemption:
9.00%.............................. -- 4,000,000 -- $ -- -- 100,000
========= ========= ======= ---------- ----------
LONG-TERM DEBT (Note 3(D)):
First mortgage bonds:
7.375% due 2003................................................................... -- 100,000
9.500% due 2005................................................................... -- 300,000
6.860% due 2008................................................................... 125,000 125,000
9.000% due 2023................................................................... -- 150,000
---------- ----------
Total first mortgage bonds...................................................... 125,000 675,000
---------- ----------
Unsecured notes:
6.000% due 2013................................................................... 78,700 78,700
5.650% due 2013................................................................... 300,000 --
9.000% due 2031................................................................... 103,093 --
* 5.580% due 2033................................................................... 27,700 27,700
---------- ----------
509,493 106,400
7.682% due to associated companies 2005-2016 (Note 7)............................. 198,843 --
---------- ----------
Total unsecured notes........................................................... 708,336 106,400
---------- ----------
16
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
7.000% due 2004-2009............................................................. 1,730 1,760
7.750% due 2003.................................................................. -- 15,000
7.670% due 2004.................................................................. 280,000 280,000
7.130% due 2007.................................................................. 120,000 120,000
7.430% due 2009.................................................................. 150,000 150,000
* 1.120% due 2015.................................................................. 39,835 39,835
7.880% due 2017.................................................................. 300,000 300,000
* 1.120% due 2018.................................................................. 72,795 72,795
* 1.150% due 2020.................................................................. 47,500 47,500
6.000% due 2020.................................................................. 62,560 62,560
6.100% due 2020.................................................................. 70,500 70,500
9.520% due 2021.................................................................. 7,500 7,500
6.850% due 2023.................................................................. -- 30,000
8.000% due 2023.................................................................. 46,100 46,100
7.625% due 2025.................................................................. 53,900 53,900
7.700% due 2025.................................................................. 43,800 43,800
7.750% due 2025.................................................................. 45,150 45,150
5.375% due 2028.................................................................. 5,993 5,993
3.400% due 2030.................................................................. 23,255 23,255
4.600% due 2030.................................................................. -- 81,640
* 1.150% due 2033.................................................................. 30,000 30,000
---------- ----------
Total secured notes............................................................ 1,400,618 1,527,288
---------- ----------
Preferred stock subject to mandatory redemption**.................................. 5,014 --
---------- ----------
Capital lease obligations (Note 2)................................................. 5,924 6,351
---------- ----------
Net unamortized premium on debt.................................................... 27,165 47,152
---------- ----------
Long-term debt due within one year**............................................... (387,414) (387,190)
---------- ----------
Total long-term debt and long-term obligations**............................... 1,884,643 1,975,001
---------- ----------
TOTAL CAPITALIZATION.................................................................. $3,759,874 $3,376,427
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2003 interest rate shown.
** The December 31, 2003 balances for Preferred Stock subject to Mandatory Redemption is classified as debt under SFAS 150.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
17
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Other
Comprehensive Number Carrying Comprehensive Retained
Income of Shares Value Income (Loss) Earnings
------------- --------- -------- ------------- --------
(Dollars in thousands)
Balance, January 1, 2001....................... 79,590,689 $ 931,962 $ -- $ 163,912
Net income.................................. $177,905 177,905
Unrealized gain on instruments, net of
$5,900,000 of income taxes................ 9,000 9,000
--------
Comprehensive income........................ $186,905
========
Cash dividends on preferred stock........... (24,838)
Cash dividends on common stock.............. (175,900)
- ------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001..................... 79,590,689 931,962 9,000 141,079
Net income.................................. $136,952 136,952
Unrealized loss on investments, net of
$(6,058,000) of income taxes.............. (9,233) (9,233)
Minimum liability for unfunded retirement
benefits,
net of $(31,359,000) of income taxes...... (44,051) (44,051)
--------
Comprehensive income........................ $ 83,668
========
Equity contribution from parent............. 50,000
Cash dividends on preferred stock........... (10,965)
Preferred stock redemption premiums......... (4,743)
- ------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002..................... 79,590,689 981,962 (44,284) 262,323
Net income.................................. $239,411 239,411
Unrealized gain on investments, net of
$19,598,000 of income taxes............... 28,255 28,255
Minimum liability for unfunded retirement
benefits, net of $13,760,000 of income
taxes..................................... 18,682 18,682
--------
Comprehensive income........................ $286,348
========
Equity contribution from parent............. 300,000
Cash dividends on preferred stock........... (7,429)
Preferred stock redemption premiums......... (93)
- ------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003..................... 79,590,689 $1,281,962 $ 2,653 $ 494,212
========================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
---------------------- -----------------------
Number Carrying Number Carrying
of Shares Value of Shares Value
--------- -------- ---------- --------
(Dollars in thousands)
Balance, January 1, 2001............ 1,624,000 $238,325 177,216 $ 106,571
Issues
9.00%........................... 4,000,000 100,000
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series R................. (50,000) (50,000)
$91.50 Series Q................. (10,716) (10,716)
$90.00 Series S................. (18,750) (18,750)
Amortization of fair market
value adjustments-
$ 7.35 Series C ................ (11)
$88.00 Series R................. (1,128)
$90.00 Series S................. (668)
-------------------------------------------------------------------------------------------
Balance, December 31, 2001.......... 1,624,000 238,325 4,087,750 124,298
Redemptions-
$7.56 Series B................. (450,000) (45,071)
$42.40 Series T................. (200,000) (96,850)
$7.35 Series C................. (10,000) (1,000)
$90.00 Series S................. (17,750) (17,010)
Amortization of fair market
value adjustments-
$7.35 Series C................. (9)
$90.00 Series S................. (258)
-------------------------------------------------------------------------------------------
Balance, December 31, 2002.......... 974,000 96,404 4,060,000 106,021
Redemptions-
$7.35 Series C................. (10,000) (1,000)
FIN 46 Deconsolidation-
9.00% Series................... (4,000,000) (100,000)
Amortization of fair market
value adjustments-
$7.35 Series C................. (7)
-------------------------------------------------------------------------------------------
Balance, December 31, 2003.......... 974,000 $ 96,404 50,000 $ 5,014*
===========================================================================================
<FN>
* December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under SFAS 150 (see note 7).
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
18
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income........................................................... $ 239,411 $ 136,952 $ 177,905
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization..................... 198,307 244,727 304,417
Nuclear fuel and capital lease amortization..................... 17,466 21,044 30,539
Other amortization.............................................. (16,278) (15,008) (14,071)
Deferred operating lease costs, net............................. (78,214) (60,200) (60,200)
Deferred income taxes, net...................................... 27,139 3,637 32,741
Amortization of investment tax credits.......................... (4,807) (4,632) (3,770)
Accrued retirement benefit obligations.......................... 7,630 (103,448) 3,837
Accrued compensation, net....................................... (8,743) 6,372 (13,886)
Cumulative effect of accounting change (Note 1(M)).............. (72,546) -- --
Receivables..................................................... (16,339) (27,159) 42,542
Materials and supplies.......................................... 5,771 (7,624) 15,949
Accounts payable................................................ (54,858) 47,147 (52,068)
Accrued taxes................................................... 76,261 (3,568) (48,877)
Accrued interest................................................ (13,895) (5,334) 959
Prepayments and other current assets............................ (294) 27,418 27,743
Other........................................................... 58,824 56,831 (78,265)
--------- --------- ---------
Net cash provided from operating activities................... 364,835 317,155 365,495
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt.................................................. 296,905 106,981 --
Preferred stock................................................. -- -- 96,739
Short-term borrowings, net...................................... -- 190,879 69,118
Equity contributions from parent................................ 300,000 50,000 --
Redemptions and Repayments-
Preferred stock................................................. (1,093) (164,674) (80,466)
Long-term debt.................................................. (677,097) (309,480) (74,230)
Short-term borrowings, net...................................... (109,212) -- --
Dividend Payments-
Common stock.................................................... -- -- (175,900)
Preferred stock................................................. (7,451) (13,782) (27,645)
--------- --------- ---------
Net cash used for financing activities........................ (197,948) (140,076) (192,384)
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions................................................... (134,899) (163,199) (154,927)
Loan payments from (to) associated companies, net.................... (5,003) 415 (10,734)
Investment in lessor notes (Note 2).................................. 44,732 39,636 16,287
Sale of assets to associated companies............................... -- -- 11,117
Contributions to nuclear decommissioning trusts...................... (29,024) (29,024) (30,468)
Other................................................................ (48,293) 5,179 (6,945)
--------- --------- ---------
Net cash used for investing activities........................ (172,487) (146,993) (175,670)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents................. (5,600) 30,086 (2,559)
Cash and cash equivalents at beginning of year....................... 30,382 296 2,855
--------- --------- ---------
Cash and cash equivalents at end of year............................. $ 24,782 $ 30,382 $ 296
========= ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................... $ 174,375 $ 186,040 $ 196,001
========= ========= =========
Income taxes.................................................... $ 24,796 $ 121,668 $ 131,801
========= ========= =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
19
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property......................................... $ 63,448 $ 77,516 $ 72,665
State gross receipts*.............................................. -- -- 27,169
Ohio kilowatt-hour excise*......................................... 68,459 66,775 42,608
Social security and unemployment................................... 4,331 3,478 2,752
Other.............................................................. 196 35 (246)
--------- --------- ---------
Total general taxes......................................... $ 136,434 $ 147,804 $ 144,948
========= ========= =========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal......................................................... $ 109,775 $ 76,364 $ 92,739
State........................................................... 29,346 14,721 16,177
--------- --------- ---------
139,121 91,085 108,916
--------- --------- ---------
Deferred, net-
Federal......................................................... 21,382 (3,661) 32,368
State........................................................... 5,757 2,146 1,125
--------- --------- ---------
27,139 (1,515) 33,493
--------- --------- ---------
Investment tax credit amortization................................. (4,807) (4,632) (4,522)
--------- --------- ---------
Total provision for income taxes............................ $ 161,453 $ 84,938 $ 137,887
========= ========= =========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income................................................... $ 58,237 $ 71,325 $ 121,197
Other income....................................................... 73,048 13,613 16,690
Cumulative effect of accounting change............................. 30,168 -- --
--------- --------- ---------
Total provision for income taxes............................ $ 161,453 $ 84,938 $ 137,887
========= ========= =========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes...................... $ 400,864 $ 221,890 $ 315,792
========= ========= =========
Federal income tax expense at statutory rate....................... $ 140,302 $ 77,662 $ 110,527
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit........... 22,817 10,964 11,246
Amortization of investment tax credits.......................... (4,807) (4,632) (4,522)
Amortization of tax regulatory assets........................... 1,087 999 1,012
Amortization of goodwill........................................ -- -- 16,530
Other, net...................................................... 2,054 (55) 3,094
--------- --------- ---------
Total provision for income taxes............................ $ 161,453 $ 84,938 $ 137,887
========= ========= =========
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences......................................... $ 477,358 $ 473,506 $ 463,344
Regulatory transition charge....................................... 302,270 371,486 424,484
Unamortized investment tax credits................................. (25,311) (27,839) (29,528)
Deferred gain for asset sale to affiliated company................. 38,394 43,193 49,735
Other comprehensive income......................................... 1,841 (31,517) 5,900
Above market leases................................................ (324,843) (350,299) (375,333)
Retirement Benefits................................................ (32,023) (42,079) (73,483)
All other.......................................................... 48,362 (29,154) (51,481)
--------- --------- ---------
Net deferred income tax liability........................... $ 486,048 $ 407,297 $ 413,638
========= ========= =========
<FN>
* Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include The Cleveland Electric
Illuminating Company (Company) and its wholly owned subsidiaries, Centerior
Funding Corporation (CFC), Centerior Financing Trust (CFT) and Shippingport
Capital Trust (see Note 7). 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 Ohio Edison Company (OE), The Toledo Edison Company
(TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light
Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric
Company (Penelec).
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 three years ended December 31, 2002
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, regulatory assets and
goodwill. Certain prior year amounts have been reclassified to conform with the
current year presentation, as described further in Note 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 northeastern 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 $10 million (billed - $6
million and unbilled - $4 million) and $11 million (billed - $8 million and
unbilled - $3 million) as of December 31, 2003 and 2002, respectively.
The Company and TE sell substantially all of their retail customers'
receivables to CFC. CFC subsequently transfers the receivables to a trust (a
Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,"
- - "qualified special purpose entity") 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 TE processed receivables for the
trust and received servicing fees of approximately $3.6 million ($2.4 million
CEI and $1.2 million TE) 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.
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 TE (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 $1.6 billion net of deferred income taxes and transition costs
related to regulatory assets as filed of $1.4 billion net of deferred income
taxes, with recovery through no later than 2008 for the Company, except where a
longer period of recovery is provided for in the settlement agreement. The
generation-related transition costs include $0.2 billion, net of deferred income
taxes, of impaired generating assets recognized as regulatory assets as
described further below, $0.4 billion, net of deferred income taxes of above
market operating lease costs and $0.5 billion, net of deferred income taxes, of
additional plant costs that were reflected on the Company's regulatory financial
statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 400 megawatts (MW) of generation capacity through 2005 at
established prices for sales to the Company's retail customers. Customer prices
are frozen through the five-year market development period, 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 $4 million to recover its
higher tax costs resulting from the Ohio deregulation legislation.
The Company's customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers. 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, CEI is requesting:
o Extension of the transition cost amortization period from 2008
to July 2009;
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 2009.
(In millions)
--------------------------------
2004.................. $192
2005.................. 219
2006.................. 129
2007.................. 145
2008.................. 164
2009.................. 46
-------------------------------
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 are expected to continue to be recovered from
customers under the Company's transition plan. Based on that plan, the Company
continues to bill and collect cost-based rates for its transmission and
distribution services, which will remain regulated; accordingly, it is
appropriate that the Company continues the application of SFAS 71 to those
operations.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2003 2002
- ---------------------------------------------------------------------------
(In millions)
Regulatory transition charge.................... $ 900 $1,066
Customer shopping incentives.................... 179 85
Customer receivables for future income taxes.... 7 8
Loss on reacquired debt......................... 14 16
Employee postretirement benefit costs........... 15 17
Component removal costs......................... (60) (47)
Other........................................... 1 --
- -------------------------------------------------------------------------
Total...................................... $1,056 $1,145
=========================================================================
Regulatory Accounting 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 $304 million of impaired plant investments were
recognized by the Company as regulatory assets recoverable as transition costs
through future regulatory cash flows. Net assets included in utility plant
relating to the operations for which the application of SFAS 71 was discontinued
were $1.4 billion 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),
including payroll and related costs such as taxes, employee benefits,
administrative and
23
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.
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, 3.4% in 2002 and
3.2% 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 TE, 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)
W. H. Sammis Unit 7........... $ 180 $123 $ -- 31.20%
Bruce Mansfield Units 1, 2
and 3....................... 127 43 25 20.42%
Beaver Valley Unit 2.......... 13 1 14 24.47%
Davis-Besse................... 248 56 84 51.38%
Perry......................... 655 161 9 44.85%
- ------------------------------------------------------------------------------------------
Total...................... $1,223 $384 $132 .
==========================================================================================
The Bruce Mansfield Plant is being leased through a sale and
leaseback transaction (see Note 2) and the above-related amounts represent
construction expenditures subsequent to the transaction.
(F) 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, reclamation of a
sludge disposal pond related to the Bruce Mansfield Plant, and closure of two
coal ash disposal sites. The ARO liability as of the date of adoption of SFAS
143 was $238.3 million, including accumulated accretion for the period from the
date the liability was incurred to the date of adoption. Accretion during 2003
was $16.5 million, bringing the ARO liability as of December 31, 2003 to $254.8
million. The ARO includes the Company's obligation for nuclear decommissioning
of the Beaver Valley Unit 2, Davis-Besse, and Perry 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 $313.6
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
24
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.
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........................................ $137 $178
Increase (Decrease):
Elimination of decommissioning expense..................... 29 29
Depreciation of asset retirement cost...................... (1) (1)
Accretion of ARO liability................................. (15) (14)
Non-regulated generation cost of removal component, net.... 9 6
Income tax effect.......................................... (9) (8)
------------------------------------------------------------------------------
Net earnings increase...................................... 13 12
-----------------------------------------------------------------------------
Net income adjusted........................................ $150 $190
=============================================================================
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 $223.1
Accretion in 2002 15.2
------------------------------------------------------
Ending balance as of December 31, 2002 $238.3
------------------------------------------------------
(G) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 3B). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the
fair value method 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% 5.0%
Risk-free interest rate...... 3.67% 4.60% 4.6%
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 each Company
recognizing any tax losses or credits the Company contributes to the
consolidated return.
25
(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.
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. $ 22 $ 39 $ (71) $ (117)
====== ====== ======= =======
Increase 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 benefit costs
(income).............................. $ 10 $ 1 $ (2) $ 15 $ 10 $ 13
===== ===== ===== ==== ==== ====
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.
27
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
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 $17 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 $12 million, recording a decrease of $4 million in an intangible
asset and crediting OCI by $5 million (offsetting previously recorded deferred
tax benefits by $3 million). The remaining balance in OCI of $25 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 $33
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, TE, OE and Penn. As a result,
the Company entered into power supply agreements (PSA) whereby FES purchases all
of the Company's nuclear generation and the generation from leased fossil
generating facilities and the Company purchases its power from FES to meet its
"provider of last resort" obligations. CFC serves as the transferor in
connection with the accounts receivable securitization for the Company and TE.
The primary affiliated companies transactions are as follows:
28
2003 2002 2001
- ------------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues from FES............ $260 $284 $334
Generating units rent from FES... 59 60 59
Ground lease with ATSI........... 7 7 7
Operating Expenses:
Purchased power under PSA........ 423 420 597
Purchased power from TE.......... 109 104 97
Transmission expenses............ 32 41 29
FESC support services............ 63 52 50
Other Income:
Interest income from ATSI........ 7 7 7
Interest income from FES......... 1 1 1
- ---------------------------------------------------------------------------
The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased
capacity entitlement. Purchased power expenses for this transaction were $109
million, $104 million and $97 million in 2003, 2002 and 2001, respectively. This
purchase is expected to continue through the end of the lease period (see Note
2).
FirstEnergy does not bill directly or allocate any of its costs to
any subsidiary company. Costs are allocated to the Company from FESC, a
subsidiary of FirstEnergy 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 $145 million payable to affiliates for
pension and OPEB obligations.
(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 $25 million received in December 2003 which was
included in the NRG settlement claim sold in January 2004 (see Note 6) and $30
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 $2.1 million in 2001. There
were no capital lease transactions in 2003 or 2002. "Other amortization" on the
Consolidated Statement of Cash Flows under Cash Flows from Operating Activities
consists of amounts from the reduction of an electric service obligation under
the Company's electric service prepayment program.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt, preferred stock subject to mandatory redemption and
investments other than cash and cash equivalents as of December 31:
2003 2002
- ----------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- ----------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt................................... $2,234 $2,444 $2,309 $2,493
Preferred stock*................................. $ 5 $ 5 $ 106 $ 113
Investments other than cash and cash equivalents:
Debt securities
- Maturity (5-10 years)....................... $ 11 $ 11 $ 11 $ 11
- Maturity (more than 10 years)............... 698 812 528 576
All other..................................... 318 318 232 232
- ----------------------------------------------------------------------------------------------------------
$1,027 $1,141 $ 771 $ 819
==========================================================================================================
<FN>
* The December 31, 2003 amount is classified as debt under SFAS 150.
</FN>
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities with similar characteristics offered by a corporation with credit
ratings similar to the Company's ratings.
29
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 ($188 million) and fixed income
securities ($124 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 $0.8 million
and $6.9 million, respectively, and interest and dividend income totaled
approximately $8.5 million and $7.3 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:
2003* 2002*
- ----------------------------------------------------------------
(In millions)
Unrealized gains (losses)........... $ 48.1 $(15.3)
Proceeds from sales................. 226.0 197.8
Realized gains (losses)............. (0.8) (6.9)
- ----------------------------------------------------------------
* 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 $59.8 million and net unrealized losses of $12.1 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....... $ 7.8 $2.3 $11.2 $9.6 $19.0 $11.9
Debt Securities......... 10.2 0.2 -- -- 10.2 0.2
- -----------------------------------------------------------------------------------------------------
Total............... $18.0 $2.5 $11.2 $9.6 $29.2 $12.1
- -------------------------------------------------------------------------------------------------------
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 $1.7 billion 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.
30
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................ $239,411 $136,952 $177,905
Add back goodwill amortization..... -- -- 47,230
-------- -------- --------
Adjusted net income................ $239,411 $136,952 $225,135
======== ======== ========
(M) CUMULATIVE EFFECT OF ACCOUNTING CHANGE-
Results for 2003 include an after-tax credit to net income of $42.4
million recorded by the Company upon adoption of SFAS 143 in January of 2003.
The Company identified applicable legal obligations as defined under the new
accounting standard for nuclear power plant decommissioning, reclamation of a
sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash
disposal sites. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $49.9 million were recorded as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $6.8
million. The asset retirement obligation liability at the date of adoption was
$238.3 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 $242.5 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
$72.5 million increase to income, or $42.4 million net of income taxes.
2. LEASES:
The Company leases certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.
The Company and TE sold their ownership interests in Bruce Mansfield
Units 1, 2 and 3 and TE sold a portion of its ownership interest in Beaver
Valley Unit 2. In connection with these sales, which were completed in 1987, the
Company and TE entered into operating leases for lease terms of approximately 30
years as co-lessees. During the terms of the leases, the Company and TE continue
to be responsible, to the extent of their combined ownership and leasehold
interest, for costs associated with the units including construction
expenditures, operation and maintenance expenses, insurance, nuclear fuel,
property taxes and decommissioning. The Company and TE have the right, at the
end of the respective basic lease terms, to renew the leases. The Company and TE
also have the right to purchase the facilities at the expiration of the basic
lease term or any renewal term at a price equal to the fair market value of the
facilities.
As co-lessee with TE, the Company is also obligated for TE's lease
payments. If TE is unable to make its payments under the Beaver Valley Unit 2
and Bruce Mansfield Plant leases, the Company would be obligated to make such
payments. No such payments have been made on behalf of TE. (TE's future minimum
lease payments as of December 31, 2003 were approximately $1.0 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...... $31.6 $33.6 $35.3
Other................. 45.9 42.8 36.4
Capital leases
Interest element...... 0.6 0.6 3.6
Other................. 0.4 0.4 19.4
- ------------------------------------------------------------------
Total rentals......... $78.5 $77.4 $94.7
==================================================================
31
The future minimum lease payments as of December 31, 2003 are:
Operating Leases
------------------------------------
Capital Lease Capital
Leases Payments Trust Net
---------------------------------------------------------------------------------------------
(In millions)
2004.................................. $ 1.0 $ 55.7 $ 28.6 $ 27.1
2005.................................. 1.0 66.7 48.3 18.4
2006.................................. 1.0 71.3 56.2 15.1
2007.................................. 1.0 57.8 48.2 9.6
2008.................................. 1.0 54.2 42.9 11.3
Years thereafter...................... 3.7 470.5 350.4 120.1
----------------------------------------------------------------------------------------------
Total minimum lease payments.......... 8.7 $776.2 $574.6 $201.6
====== ====== ======
Interest portion...................... 2.8
-------------------------------------------------
Present value of net minimum
lease payments...................... 5.9
Less current portion.................. 0.4
-------------------------------------------------
Noncurrent portion.................... $ 5.5
=================================================
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 $611 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 $31 million per year).
The total above-market lease obligation of $457 million associated with the
Bruce Mansfield Plant is being amortized on a straight-line basis through the
end of 2016 (approximately $29 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 $789 million, of which $60 million is current.
The Company and TE refinanced high-cost fixed obligations related to
their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through
a lower cost transaction in June and July 1997. In a June 1997 offering
(Offering), the two companies pledged $720 million aggregate principal amount
($575 million for the Company and $145 million for TE) of first mortgage bonds
due through 2007 to a trust as security for the issuance of a like principal
amount of secured notes due through 2007. The obligations of the two companies
under these secured notes are joint and several. Using available cash,
short-term borrowings and the net proceeds from the Offering, the two companies
invested $906.5 million ($569.4 million for the Company and $337.1 million for
TE) in a business trust, in June 1997. The trust used these funds in July 1997
to purchase lease notes and redeem all $873.2 million aggregate principal amount
of 10-1/4% and 11-1/8% secured lease obligation bonds (SLOBs) due 2003 and 2016.
The SLOBs were issued by a special-purpose-funding corporation in 1988 on behalf
of lessors in the two companies' 1987 sale and leaseback transaction. The
Shippingport arrangement effectively reduces lease costs related to that
transaction (see Note 7 for FIN 46R discussion).
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:
32
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
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 1G - "Stock-Based Compensation."
33
(C) PREFERRED AND PREFERENCE STOCK-
The Company's preferred stock may be redeemed in whole, or in part,
with 30-90 days' notice.
The preferred dividend rate on the Company's Series L fluctuates
based on prevailing interest rates and market conditions. The dividend rate for
this issue was 7% in 2003.
The Company has three million authorized and unissued shares of
preference stock having no par value.
(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 covenants. There
also exists cross-default provisions among financing agreements of FirstEnergy
and the Company.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
- ----------------------------------------------
2004................................ $386
2005................................ 10
2006................................ 12
2007................................ 129
2008................................ 140
- ---------------------------------------------
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. The amount is $98.5 million in 2004, which represents the next time debt
holders may exercise this provision.
The Company's obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds. Certain pollution
control revenue bonds are entitled to the benefit of an irrevocable bank letter
of credit of $48.1 million and a noncancelable municipal bond insurance policy
of $30.0 million to pay principal of, or interest on, the pollution control
revenue bonds. To the extent that drawings are made under the letter of credit
or policies, the Company is entitled to a credit against its obligation to repay
that bond. The Company pays an annual fee of 1.125% of the amount of the letter
of credit to the issuing bank and is obligated to reimburse the bank for any
drawings thereunder.
The Company and TE have unsecured letters of credit of approximately
$215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2
that expire in April 2005. The Company and TE are jointly and severally liable
for the letters of credit (see Note 2).
(E) LONG-TERM DEBT: PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Effective July 1, 2003, upon adoption of SFAS 150 (see Note 7), the
Company reclassified as debt its preferred stock subject to mandatory
redemption. Prior year amounts were not reclassified.
The Company's $7.35 C series has an annual sinking fund requirement
for 10,000 shares with annual sinking fund requirements for the next five years
of $1.0 million in each year 2004-2008.
(F) LONG-TERM DEBT: SUBORDINATED DEBENTURES TO AFFILIATED TRUSTS-
The Company formed a wholly owned statutory business trust to sell
preferred securities and invest the gross proceeds in the 9.00% subordinated
debentures of the Company. The sole assets of the trust are the applicable
subordinated debentures. Interest payment provisions of the subordinated
debentures match the distribution payment provisions of the trust's preferred
securities. In addition, upon redemption or payment at maturity of subordinated
debentures, the trust's preferred securities will be redeemed on a pro rata
basis at their liquidation value. Under certain circumstances, the applicable
subordinated debentures could be distributed to the holders of the outstanding
preferred securities of the trust in the event that the trust is liquidated. The
Company has effectively provided a full and unconditional guarantee of payments
due on the trust's preferred securities. The trust's preferred securities are
redeemable at 100% of their principal amount at the Company's option beginning
in December 2006.
34
Interest on the subordinated debentures (and therefore distributions
on the trust's preferred securities) may be deferred for up to 60 months, but
the Company may not pay dividends on, or redeem or acquire, any of its
cumulative preferred or common stock until deferred payments on its subordinated
debentures are paid in full.
Upon adoption of FIN 46R, the statutory business trust discussed
above is not consolidated on the Company's financial statements as of December
31, 2003 (see Note 7).
(G) COMPREHENSIVE INCOME-
Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common stockholder's
equity except those resulting from transactions with FirstEnergy. As of December
31, 2003, accumulated other comprehensive loss consisted of a minimum liability
for unfunded retirement benefits of $(25.4) million and unrealized gains on
investments in securities available for sale of $28.0 million.
4. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As
of December 31, 2003, the Company had total short-term borrowings of $188.2
million from its affiliates. The weighted average interest rates on short-term
borrowings outstanding as of December 31, 2003 and 2002, were 2.2% and 1.8%,
respectively.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$275 million for property additions and improvements from 2004-2006, of which
approximately $92 million is applicable to 2004. Investments for additional
nuclear fuel during the 2004-2006 period are estimated to be approximately $61
million, of which approximately $29 million applies to 2004. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $60 million and $30 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 $121.4 million per incident but
not more than $12.1 million in any one year for each incident.
The Company is also insured as to its respective interests in Beaver
Valley Unit 2, Davis-Besse and Perry under policies issued to the operating
company for each plant. Under these policies, up to $2.75 billion is provided
for property damage and decontamination and decommissioning costs. The Company
has also obtained approximately $382 million of insurance coverage for
replacement power costs for its respective interests in Beaver Valley Unit 2,
Davis-Besse and Perry. Under these policies, the Company can be assessed a
maximum of approximately $20.5 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
35
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
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-benefit" 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.
36
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 $2 million as of December 31, 2003. The Company accrues
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 Company's
plants. In addition, Ohio and Pennsylvania have water quality standards
applicable to the Company's 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) LEGAL MATTERS AND OTHER CONTINGENCIES
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against FirstEnergy and its subsidiaries.
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 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.
37
6. SALE OF GENERATING ASSETS:
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale
had included the 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants
owned by the Company. On August 8, 2002, FirstEnergy notified NRG that it was
canceling the agreement because NRG stated that it could not complete the
transaction under the original terms of the agreement. 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 - $131 million) in January 2004.
In December 2002, FirstEnergy decided to retain ownership of these
plants after reviewing other bids it subsequently received from other parties
who had expressed interest in purchasing the plants. Since FirstEnergy did not
execute a sales agreement by year-end, the Company reflected approximately $45
million ($26 million net of tax) of previously unrecognized depreciation and
other transaction costs in the fourth quarter of 2002 related to these plants
from November 2001 through December 2002 on its Consolidated Statement of
Income.
7. 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 TE 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 TE. Upon adoption of FIN 46R, the
Company was determined to be the primary beneficiary of Shippingport, and
therefore consolidated the entire trust as of December 31, 2003. As a result,
Shippingport's note payable to TE of approximately $208 million ($9 million
current) is recognized as long-term debt on the Consolidated Balances Sheets.
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.
As described in Note 3(F), the Company created a statutory business
trust to issue trust preferred securities in the amount of $100 million.
Application of the guidance in FIN 46R resulted in the holders of the preferred
securities being considered the primary beneficiaries of these trusts.
Therefore, the Company has deconsolidated the trust and recognized an equity
investment in the trust of $3 million and subordinated debentures to the trust
of $103 million as of December 31, 2003.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
financial instruments that embody obligations for the issuer are required to be
classified as liabilities. SFAS 150 was effective immediately for financial
instruments entered into or modified after May 31, 2003 and effective at the
beginning of the first interim period beginning after June 15, 2003 for all
other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, the Company
reclassified as debt the preferred stock subject to mandatory redemption with a
carrying value of approximately $5 million as of December 31, 2003. Dividends on
preferred stock subject to mandatory redemption on the Company's Consolidated
Statements of Income, which were not included in net interest charges prior to
the adoption of SFAS 150, are now included in net interest charges for the six
months ended December 31, 2003.
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.
38
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 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 following summarizes certain consolidated operating results by
quarter for 2003 and 2002.
March 31, June 30, September 30, December 31,
Three Months Ended 2003 2003 2003 2003 (a)
- ------------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $419.8 $412.1 $496.7 $392.2
Operating Expenses and Taxes................ 365.8 367.6 396.7 335.6
- -------------------------------------------------------------------------------------------------------------------
Operating Income ........................... 54.0 44.5 100.0 56.6
Other Income................................ 4.7 4.7 6.5 81.9
Net Interest Charges........................ 43.5 39.9 38.6 33.9
- -------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Accounting Change........................ 15.2 9.3 67.9 104.6
Cumulative Effect of Accounting Change
(Net of Income Taxes).................... 42.4 -- -- --
Net Income.................................. $ 57.6 $ 9.3 $ 67.9 $104.6
===================================================================================================================
Earnings Applicable to Common Stock $ 58.4 $ 7.5 $ 66.0 $100.0
===================================================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
- ------------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $433.3 $462.9 $538.9 $408.6
Operating Expenses and Taxes................ 375.8 355.8 419.0 387.0
- -------------------------------------------------------------------------------------------------------------------
Operating Income ........................... 57.5 107.1 119.9 21.6
Other Income................................ 5.2 3.4 5.6 1.8
Net Interest Charges........................ 47.8 46.8 47.3 43.3
Net Income (Loss)........................... $ 14.9 $ 63.7 $ 78.2 $(19.8)
===================================================================================================================
Earnings (Loss) Applicable to Common Stock $ 8.3 $ 60.6 $ 75.1 $(22.8)
===================================================================================================================
<FN>
(a) Net income for the three months ended December 31, 2003, was increased by
$3.2 million due to adjustments that were subsequently capitalized to
construction projects in the fourth quarter. The adjustments included $0.3
million, $1.2 million and $1.7 million of costs charged to expense in the
first, second and third quarters, respectively. Management concluded that
the adjustments were not material to the consolidated financial statements
for any quarter of 2003.
</FN>
39
Report of Independent Auditors
To the Stockholders and Board of Directors of The Cleveland Electric
Illuminating 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 Cleveland
Electric Illuminating Company (a wholly owned subsidiary of FirstEnergy Corp.)
and subsidiaries 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 of 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
40