Exhibit 13.1
OHIO EDISON COMPANY
2002 ANNUAL REPORT TO STOCKHOLDERS
Ohio Edison Company is a wholly owned electric utility operating
subsidiary of FirstEnergy Corp. Ohio Edison engages in the generation,
distribution and sale of electric energy to communities in an area of 7,500
square miles in central and northeastern Ohio and, through its wholly owned
Pennsylvania Power Company subsidiary, 1,500 square miles in western
Pennsylvania. It also engages in the sale, purchase and interchange of electric
energy with other electric companies.
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.............................. 21-36
Report of Independent Auditors.......................................... 37
Report of Independent Public Auditors................................... 38
OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN THOUSANDS)
Operating Revenues................................ $2,948,675 $3,056,464 $2,726,708 $2,686,949 $2,519,662
---------------------------------------------------------------
Operating Income.................................. $ 453,831 $ 466,819 $ 482,321 $ 473,042 $ 486,920
---------------------------------------------------------------
Income Before Extraordinary Item.................. $ 356,159 $ 350,212 $ 336,456 $ 297,689 $ 301,320
---------------------------------------------------------------
Net Income........................................ $ 356,159 $ 350,212 $ 336,456 $ 297,689 $ 270,798
---------------------------------------------------------------
Earnings on Common Stock.......................... $ 349,649 $ 339,510 $ 325,332 $ 286,142 $ 258,828
---------------------------------------------------------------
Total Assets...................................... $7,790,041 $7,915,953 $8,154,151 $8,700,746 $8,923,826
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CAPITALIZATION AT DECEMBER 31:
Common Stockholder's Equity.................... $2,839,255 $2,671,001 $2,556,992 $2,624,460 $2,681,873
Preferred Stock:
Not Subject to Mandatory Redemption.......... 100,070 200,070 200,070 200,070 211,870
Subject to Mandatory Redemption.............. 13,500 134,250 135,000 140,000 145,000
Long-Term Debt................................. 1,219,347 1,614,996 2,000,622 2,175,812 2,215,042
---------------------------------------------------------------
Total Capitalization......................... $4,172,172 $4,620,317 $4,892,684 $5,140,342 $5,253,785
---------------------------------------------------------------
CAPITALIZATION RATIOS:
Common Stockholder's Equity.................... 68.1% 57.8% 52.3% 51.1% 51.0%
Preferred Stock:
Not Subject to Mandatory Redemption.......... 2.4 4.3 4.1 3.9 4.0
Subject to Mandatory Redemption.............. 0.3 2.9 2.7 2.7 2.8
Long-Term Debt................................. 29.2 35.0 40.9 42.3 42.2
---------------------------------------------------------------
Total Capitalization......................... 100.0% 100.0% 100.0% 100.0% 100.0%
---------------------------------------------------------------
DISTRIBUTION KILOWATT-HOUR DELIVERIES (MILLIONS):
Residential.................................... 10,233 9,646 9,432 9,483 8,773
Commercial..................................... 7,994 7,967 8,221 8,238 7,590
Industrial..................................... 10,672 10,995 11,631 11,310 10,803
Other.......................................... 154 152 151 151 150
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Total.......................................... 29,053 28,760 29,435 29,182 27,316
---------------------------------------------------------------
CUSTOMERS SERVED:
Residential.................................... 1,041,825 1,033,414 1,014,379 1,016,793 1,004,552
Commercial..................................... 119,771 118,469 116,931 115,581 113,820
Industrial..................................... 4,500 4,573 4,569 4,627 4,598
Other.......................................... 1,756 1,664 1,606 1,539 1,476
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Total.......................................... 1,167,852 1,158,120 1,137,485 1,138,540 1,124,446
---------------------------------------------------------------
Number of Employees .............................. 1,569 1,618 1,647 2,734 2,832
1
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate", "potential", "expect", "believe", "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), availability
and cost of capital, inability of the Davis-Besse Nuclear Power Station to
restart (including because of an inability to obtain a favorable final
determination from the Nuclear Regulatory Commission) in the fall of 2003,
inability to accomplish or realize anticipated benefits from strategic goals and
other similar factors.
CORPORATE SEPARATION
Beginning on January 1, 2001, Ohio customers were able to choose
their electricity suppliers as a result of legislation which restructured the
electric utility industry. That legislation required unbundling the price for
electricity into its component elements - including generation, transmission,
distribution and transition charges. Ohio Edison (OE) and Pennsylvania Power
(Penn) continue to deliver power to homes and businesses through their existing
distribution systems and maintain the "provider of last resort" (PLR)
obligations under their respective rate plans. As a result of the transition
plan, FirstEnergy's electric utility operating companies (EUOC) entered into
power supply agreements whereby FirstEnergy Solutions Corp. (FES) purchases all
of the EUOC nuclear generation, and leases EUOC fossil generating facilities.
The Ohio EUOC and Penn are "full requirements" customers of FES to enable them
to meet their PLR responsibilities in their respective service areas.
The effect on OE's and Penn's (Companies) reported results of
operations during 2001 from FirstEnergy's corporate separation plan and the
Companies' sale of transmission assets to American Transmission Systems, Inc.
(ATSI) in September 2000, are summarized in the following table:
CORPORATE RESTRUCTURING - 2001 INCOME STATEMENT EFFECTS
- --------------------------------------------------------------------------------------------
INCREASE (DECREASE)
CORPORATE
SEPARATION ATSI TOTAL
---------- ---- -----
(IN MILLIONS)
Operating Revenues:
Power supply agreement with FES................ $ 355.9 $ -- $ 355.9
Generating units rent.......................... 178.8 -- 178.8
Ground lease with ATSI......................... -- 3.1 3.1
- --------------------------------------------------------------------------------------------
TOTAL OPERATING REVENUES EFFECT................ $ 534.7 $ 3.1 $ 537.8
============================================================================================
Operating Expenses and Taxes:
Fossil fuel costs.............................. $ (264.3)(a) $ -- $ (264.3)
Purchased power costs.......................... 1,025.9(b) -- 1,025.9
Other operating costs.......................... (157.1)(a) 28.6 (d) (128.5)
Provision for depreciation and amortization.... -- (12.9)(e) (12.9)
General taxes.................................. (4.8)(c) (15.2)(e) (20.0)
Income taxes................................... (23.4) 5.2 (18.2)
- --------------------------------------------------------------------------------------------
TOTAL OPERATING EXPENSES EFFECT................ $ 576.3 $ 5.7 $ 582.0
============================================================================================
OTHER INCOME..................................... $ -- $10.7 (F) $ 10.7
============================================================================================
(a) Transfer of fossil operations to FirstEnergy Generation Company (FGCO).
(b) Purchased power from power supply agreement (PSA).
(c) Payroll taxes related to employees transferred to FGCO.
(d) Transmission services received from ATSI.
(e) Depreciation and property taxes related to transmission assets sold to
ATSI.
(f) Interest on note receivable from ATSI.
RESTATED FINANCIAL STATEMENTS FOR CHANGE IN METHOD OF AMORTIZING OHIO TRANSITION
COSTS
OE has restated its financial statements for the year ended December
31, 2002, to reflect a change in the method of amortizing the costs associated
with the Ohio transition plan. OE amortizes transition costs using the effective
interest method. The amortization schedules originally developed at the
beginning of the transition plan in 2001 in
2
applying this method were based on total transition revenues, including revenues
designed to recover costs which have not yet been incurred and are not reflected
as regulatory assets in the financial statements prepared under generally
accepted accounting principles (GAAP). OE has revised the amortization schedules
under the effective interest method to consider only revenues relating to
transition regulatory assets recognized on the GAAP balance sheet. The impact of
this change will result in higher amortization of these regulatory assets in the
first several years of the transition cost recovery period compared with the
method previously applied. The change in method results in no change in total
amortization of the regulatory assets that are recovered from January 1, 2001,
through the transition period which is expected to end in 2006.
After giving effect to the restatement, total transition cost
amortization (including above market leases) is expected to approximate the
following for the years from 2003 through 2006 (in millions).
2003.............. $389
2004.............. 456
2005.............. 553
2006.............. 178
The revised amortization method is expected to decrease pre-tax
income by $13 million in 2003 and $10 million in 2004. It should increase pretax
income that would have been reported using the previous method by $8 million in
2005 and $22.3 million in 2006.
The change in amortization resulted in a decrease in net income of
$5.4 million and included an increase in net income of $15.4 million from the
cumulative impact of the adjustments related to 2001 and a $20.8 million
decrease in net income for additional amortization expense in 2002. The net
adjustment is reflected as an increase of $14.7 million in depreciation and
amortization expense and a decrease of $9.3 million in income tax expense in the
accompanying consolidated statement of income as restated.
The Company has also included in this restatement certain immaterial
adjustments that were not previously recognized in 2002. The impact of these
adjustments reduced net income reported for 2002 by $1.9 million. See Note 1(M)
to the consolidated financial statements.
The effects of the changes on the Consolidated Statement of Income
previously reported for the year ended December 31, 2002 are as follows:
AS PREVIOUSLY AS
REPORTED RESTATED
-------- --------
(IN THOUSANDS)
Revenues $ 2,948,675 $ 2,948,675
Expenses 2,486,990 2,494,844
Other income 42,329 42,859
----------- -----------
Income before net interest charges 504,014 496,690
Net interest charges 140,531 140,531
Net income $ 363,483 $ 356,159
Preferred stock dividend requirements 6,510 6,510
----------- -----------
Earnings on common stock $ 356,973 $ 349,649
=========== ===========
RESULTS OF OPERATIONS
Earnings on common stock in 2002 increased 3.0% to $349.6 million in
2002 from $339.5 million in 2001 and $325.3 million in 2000. The earnings
increase in 2002 primarily resulted from reduced financing costs, which more
than offset lower operating income and reduced investment income. Excluding the
effects shown in the corporate restructuring table above, earnings on common
stock increased by 14.7% in 2001 from 2000, being favorably affected by reduced
operating expenses and taxes, and lower net interest charges, which were
substantially offset by reduced operating revenues.
Operating revenues decreased by $107.8 million or 3.5% 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 changes in wholesale revenues. Retail kilowatt-hour sales
declined by 8.7% in 2002 from the prior year, with declines in all customer
sectors (residential, commercial and industrial), resulting in a $73.1 million
reduction in
3
generation sales revenue. Our lower generation kilowatt-hour sales resulted
primarily from customer choice in Ohio. Sales of electric generation by
alternative suppliers as a percent of total sales delivered in our franchise
area increased to 20.9% in 2002 from 12.5% in 2001, while our share of electric
generation sales in our franchise areas decreased by 8.4% compared to the prior
year. Distribution deliveries increased 1.0% in 2002 compared with 2001, which
increased revenues from electricity throughput by $18.5 million in 2002 from the
prior year. The higher distribution deliveries resulted from additional
residential demand due to warmer summer weather that was offset in part by the
effect that continued sluggishness in the economy had on demand by commercial
and industrial customers. Transition plan incentives, provided to customers to
encourage switching to alternative energy providers, further reduced operating
revenues by $27.6 million in 2002 from the prior year. These revenue reductions
are deferred for future recovery under our transition plan and do not materially
affect current period earnings. Sales revenues from wholesale customers
decreased by $18.0 million in 2002 compared to 2001, due to a decline in market
prices.
Excluding the effects shown in the table above under corporate
separation, operating revenues decreased by $208.0 million or 7.6% in 2001 from
2000. Customer choice in Ohio and the influence of a declining national economy
on our regional business activity combined to lower operating revenues. Electric
generation services provided by other suppliers in the Companies' service area
increased to 12.5% of total energy delivered from 1.5% in 2000. Overall, retail
generation sales declined in all customer categories resulting in a 13.1%
reduction in kilowatt-hour sales from the prior year. As part of Ohio's electric
utility restructuring law, the implementation of a 5% reduction in generation
charges for residential customers reduced operating revenues by approximately
$26.6 million in 2001, compared to 2000. Distribution deliveries declined 2.3%
in 2001 from the prior year reflecting the impact of a weaker economy that
contributed to lower commercial and industrial kilowatt-hour sales. Operating
revenues were also lower in 2001 from the prior year due to the absence of
revenues associated with the low-income payment plan now administered by the
Ohio Department of Development; there was also a corresponding reduction in
other operating costs associated with that change. Revenues from kilowatt-hour
sales to wholesale customers declined by $54.3 million in 2001 from 2000, with a
corresponding 42.0% reduction in kilowatt-hour sales.
CHANGES IN KWH SALES 2002 2001
--------------------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail................................ (8.7)% (13.1)%
Wholesale............................. 10.6% (42.0)%
--------------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES......... (0.6)% (20.5)%
==============================================================
Distribution Deliveries:
Residential........................... 6.1% 2.3%
Commercial and industrial............. (1.6)% (4.5)%
--------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES........... 1.0% (2.3)%
==============================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $94.8 million in
2002 and increased by $345.3 million in 2001 from 2000. Excluding the effects of
restructuring, total 2001 operating expenses and taxes were $236.7 million lower
than the prior year. The following table presents changes from the prior year by
expense category excluding the impact of restructuring on 2001 changes.
OPERATING EXPENSES AND TAXES - CHANGES 2002 2001
-----------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
INCREASE (DECREASE) (IN MILLIONS)
Fuel and purchased power..................... $(109.6) $ (84.1)
Nuclear operating costs...................... (28.9) 14.7
Other operating costs........................ 51.3 (14.6)
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TOTAL OPERATION AND MAINTENANCE EXPENSES... (87.2) (84.0)
Provision for depreciation and amortization.. (39.4) (140.8)
General taxes................................ 23.5 (52.3)
Income taxes................................. 8.3 40.4
-----------------------------------------------------------------------
TOTAL OPERATING EXPENSES AND TAXES......... $ (94.8) $(236.7)
=======================================================================
Lower fuel and purchased power costs in 2002, compared to 2001,
resulted from a $114.4 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 decreased $28.9 million, primarily due to one
less refueling outage in 2002 compared to the prior year. The $51.3 million
increase in other operating costs resulted principally from higher employee
benefit costs and, to a lesser extent, increased distribution costs due in part
to storm damage.
4
The decrease in fuel and purchased power costs in 2001, compared to
2000, reflects the transfer of fossil operations to FGCO, with the Companies'
power requirements being provided under the PSA. Nuclear operating costs
increased by $14.7 million in 2001 from the prior year due to two refueling
outages compared to one refueling outage in 2000; however, the Perry Plant also
experienced two unplanned outages in 2001. Other operating costs decreased by
$14.6 million in 2001 from the prior year, reflecting a reduction in low-income
payment plan customer costs, lower storm damage costs, the absence of costs
incurred in 2000 related to the development of a distribution communications
system, reduced uncollectible accounts and customer program expenses, offset in
part by the absence in 2001 of gains from the sale of emission allowances.
Charges for depreciation and amortization decreased by $39.4 million
in 2002 from 2001 primarily due to higher shopping incentive deferrals and
tax-related deferrals under OE's transition plan. In 2001, depreciation and
amortization decreased by $140.8 million from the prior year due to lower
incremental transition cost amortization and new deferrals for shopping
incentives under FirstEnergy's Ohio transition plan compared to the accelerated
cost recovery in connection with our prior regulatory plan.
General taxes increased by $23.5 million in 2002 from 2001
principally due to additional property taxes and the absence in 2002 of a
one-time benefit of $15 million resulting from the successful resolution of
certain property tax issues in the prior year. In 2001, general taxes decreased
by $52.3 million from 2000 due to reduced property taxes and other state tax
changes in connection with the Ohio electric industry restructuring and the
one-time $15 million benefit. The reduction in general taxes was partially
offset by $38.0 million of new Ohio franchise taxes in 2001, which are
classified as state income taxes on the Consolidated Statements of Income.
Other Income
Other income decreased by $25.8 million in 2002 from the prior year,
primarily due to lower investment income.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $44.8
million in 2002 and by $16.6 million in 2001, compared to the prior year. We
continued to redeem and refinance outstanding debt and preferred stock during
2002 - net redemptions and refinancing activities totaled $542.0 million and
$14.5 million, respectively, and will result in annualized savings of $37.1
million.
CAPITAL RESOURCES AND LIQUIDITY
Our improving financial position reflects ongoing efforts to
increase competitiveness and enhance shareholder value. We have continued to
strengthen our financial position over the past five years by improving our
fixed charge coverage ratios. Our corporate indenture ratio, which is used to
measure our ability to issue first mortgage bonds, increased from 6.21 in 1997
to 11.35 in 2002, which enhances our financial flexibility. Over the same
period, our charter ratio, a measure of our ability to issue preferred stock,
improved from 2.35 to 5.07 and our common stockholder's equity as a percentage
of capitalization rose from approximately 48% at the end of 1997 to 68% at the
end of 2002. Over the last five years, we have reduced the average cost of
long-term debt from 7.77% in 1997 to 5.77% at the end of 2002.
Changes in Cash Position
As of December 31, 2002, we had $20.5 million of cash and cash
equivalents, compared with $4.6 million as of December 31, 2001. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Our consolidated net cash from operating activities is provided by
our regulated energy services. Net cash provided from operating activities was
$1.057 billion in 2002 and $668 million in 2001. Cash flows provided from 2002
and 2001 operating activities are as follows:
OPERATING CASH FLOWS 2002 2001
----------------------------------------------------------
(IN MILLIONS)
Cash earnings (1).................... $ 711 $743
Working capital and other............ 346 (75)
----------------------------------------------------------
Total................................ $1,057 $668
==========================================================
(1) Includes net income, depreciation and amortization, deferred
costs recoverable as regulatory assets, deferred income taxes,
investment tax credits and major noncash charges.
5
Cash Flows From Financing Activities
In 2002, the net cash used for financing activities of $599 million
primarily reflects the redemptions of debt and preferred stock shown below. The
following table provides details regarding new issues and redemptions during
2002:
SECURITIES ISSUED OR REDEEMED IN 2002
--------------------------------------------------------------
(IN MILLIONS)
New Issues
Pollution Control Notes.................... $ 15
Redemptions
First Mortgage Bonds....................... $ 280
Pollution Control Notes.................... 15
Secured Notes.............................. 127
Preferred Stock............................ 221
Other, principally redemption premiums..... 4
--------------------------------------------------------------
$ 647
Short-term Borrowings, Net...................... $ 162
--------------------------------------------------------------
In 2001, net cash used for financing activities totaled $432
million, primarily due to the redemption of debt and the payment of common stock
dividends to FirstEnergy.
We had about $458.2 million of cash and temporary investments and
approximately $407.7 million of short-term indebtedness at the end of 2002.
Available borrowing capability under bilateral bank facilities totaled $18.5
million as of December 31, 2002. We had the capability to issue $1.7 billion of
additional first mortgage bonds on the basis of property additions and retired
bonds. Based upon applicable earnings coverage tests we could issue a total of
$3.1 billion of preferred stock (assuming no additional debt was issued) as of
the end of 2002. At the end of 2002, our common equity as a percentage of
capitalization stood at 68% compared to 58% at the end of 2001. The higher
common equity percentage in 2002 compared to 2001 resulted from net redemptions
of preferred stock and long-term debt and the increase in retained earnings.
Cash Flows From Investing Activities
Net cash flows used in investing activities totaled $443 million in
2002. The net cash flows used for investing resulted from loans to associated
companies and property additions, which were offset in part by a reduction of
the PNBV Capital Trust investment. Expenditures for property additions primarily
include expenditures supporting our distribution of electricity.
In 2001, net cash flows used in investing activities totaled $249
million, principally due to property additions, the sale of property to
affiliates as part of corporate separation and the sale to ATSI discussed above.
Our cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
we expect to meet our contractual obligations with cash from operations.
Thereafter, we expect to use a combination of cash from operations and funds
from the capital markets.
LESS THAN 1-3 3-5 MORE THAN
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR YEARS YEARS 5 YEARS
- -----------------------------------------------------------------------------------------
(IN MILLIONS)
Long-term debt.............. $1,776 $250 $234 $ 12 $1,280
Short-term borrowings....... 408 408 -- -- --
Preferred stock (1)......... 14 1 2 11 --
Capital leases (2).......... 20 3 9 5 3
Operating leases (2)........ 1,311 74 162 160 915
Purchases (3)............... 239 45 50 62 82
- --------------------------------------------------------------------------------------
Total.................. $3,768 $781 $457 $250 $2,280
- --------------------------------------------------------------------------------------
(1) Subject to mandatory redemption
(2) Operating lease payments are net of capital trust receipts of $653.9
million (see Note 2).
(3) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing
6
Our capital spending for the period 2003-2007 is expected to be
about $391 million (excluding nuclear fuel) of which approximately $139 million
applies to 2003. Investments for additional nuclear fuel during the 2003-2007
period are estimated to be approximately $97 million, of which about $42 million
relates to 2003. During the same periods, our nuclear fuel investments are
expected to be reduced by approximately $85 million and $41 million,
respectively, as the nuclear fuel is consumed.
On February 22, 2002, Moody's Investor Service changed its credit
rating outlook for FirstEnergy from stable to negative. The change was based
upon a decision by the Commonwealth Court of Pennsylvania to remand to the
Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision
on the mechanism for sharing merger savings and reversed the PPUC's decisions
regarding rate relief and accounting deferrals rendered in connection with its
approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed
its outlook for FirstEnergy's credit ratings from stable to negative citing
recent developments including: damage to the Davis-Besse reactor vessel head
(the Companies have no ownership interest in Davis-Besse), the Pennsylvania
Commonwealth Court decision, and deteriorating market conditions for some sales
of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its
rating outlook for FirstEnergy to negative from stable. The revised outlook
reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's
judgment about NRG's financial ability to consummate the purchase of four power
plants (none owned by the Companies) from FirstEnergy and Fitch's expectation of
subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while
NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants
to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows
sufficiently stable to support a continued (although delayed) program of debt
and preferred stock redemption. S&P noted that it would continue to closely
monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P
indicated its concern about FirstEnergy's disclosure of non-cash charges related
to deferred costs in Pennsylvania, pension and other post-retirement benefits,
and Emdersa (FirstEnergy's Argentina operations), which were higher than
anticipated in the third quarter of 2002. S&P identified the restart of the
Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as
key to maintaining its current debt ratings. S&P also identified other issues it
would continue to monitor including: FirstEnergy's deleveraging efforts, free
cash generated during 2003, the Jersey Central Power & Light Company rate case,
successful hedging of its short power position, and continued capture of
projected merger savings. While FirstEnergy anticipates being prepared to
restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory
Commission (NRC) must authorize the unit's restart following a formal inspection
process prior to its returning the unit to service. Significant delays in the
planned date of Davis-Besse's return to service or other factors (identified
above) affecting the speed with which FirstEnergy reduces debt could put
additional pressure on the Companies' credit ratings.
On July 25, 2003, Standard & Poor's (S&P) issued comments on
FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse
outage and the NJBPU decision on the JCP&L rate case. S&P noted that additional
costs from the Davis-Besse outage extension, the NJBPU ruling on recovery of
deferred energy costs and additional capital investments required to improve
reliability in the New Jersey shore communities will adversely affect
FirstEnergy's cash flow and deleveraging plans. S&P noted that it continues to
assess FirstEnergy's plans to determine if projected financial measures are
adequate to maintain its current rating.
On August 7, 2003, S&P affirmed its "BBB" corporate credit rating
for FirstEnergy. However, S&P stated that although FirstEnergy generates
substantial free cash, that its strategy for reducing debt had deviated
substantially from the one presented to S&P around the time of the GPU merger
when the current rating was assigned. S&P further noted that their affirmation
of FirstEnergy's corporate credit rating was based on the assumption that
FirstEnergy would take appropriate steps quickly to maintain its investment
grade ratings including the issuance of equity and possible sale of assets. Key
issues being monitored by S&P included reaudit of CEI and TE by
PricewaterhouseCoopers LLP, restart of Davis-Besse, FirstEnergy's liquidity
position, its ability to forecast provider-of-last-resort load and the
performance of its hedged portfolio, and capture of merger synergies. On August
11, 2003, S&P stated that a recent U.S. District Court ruling (see Environmental
Matters below) with respect to the Sammis Plant is negative for FirstEnergy's
credit quality.
Other Obligations
Obligations not included on our Consolidated Balance Sheet primarily
consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver
Valley Unit 2, which are reflected in the operating lease payments disclosed
above (see Note 2 - Leases). The present value as of December 31, 2002, of these
sale and leaseback operating lease commitments, net of trust investments, total
$695 million.
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. We are subject to the inherent risks related to refinancing
maturing debt by issuing new debt securities. As discussed in Note 2, our
investment in the PNBV Capital Trust effectively reduces future lease
obligations, also reducing interest rate risk. Changes in the market value of
our nuclear decommissioning trust funds had been recognized by making
corresponding changes to other comprehensive income, as described in
7
Note 1 - Utility Plant and Depreciation. While fluctuations in the fair value of
our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI
initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have
the opportunity to recover from ratepayers the difference between the
investments held in trust and their decommissioning obligations. Thus, in
absence of disallowed costs, there will be no earning effect from fluctuations
in their decommissioning trust balances. As of December 31, 2002,
decommissioning trust balances totaled $1.050 billion with $698 million held by
our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002,
trust balances included 51% of equity and 49% of debt instruments.
The table below presents principal amounts and related weighted
average interest rates by year of maturity for our investment portfolio, debt
obligations and preferred stock with mandatory redemption provisions.
COMPARISON OF CARRYING VALUE TO FAIR VALUE
- ----------------------------------------------------------------------------------------------------------
THERE- FAIR
2003 2004 2005 2006 2007 AFTER TOTAL VALUE
- ----------------------------------------------------------------------------------------------------------
ASSETS (DOLLARS IN MILLIONS)
Investments other than Cash
and Cash Equivalents:
Fixed Income................. $ 31 $306 $184 $ 34 $ 37 $649 $1,241 $1,284
Average interest rate..... 8.0% 7.8% 7.9% 8.2% 8.4% 7.5% 7.7%
- ----------------------------------------------------------------------------------------------------------
Liabilities
- ----------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $250 $ 97 $137 $ 6 $ 6 $569 $1,065 $1,150
Average interest rate .... 8.2% 7.3% 7.2% 7.9% 7.9% 7.1% 7.4%
Variable rate................ $711 $ 711 $ 711
Average interest rate..... 2.9% 2.9%
Short-term Borrowings........ $408 $ 408 $ 408
Average interest rate..... 1.6% 1.6%
- ---------------------------------------------------------------------------------------------------------
Preferred Stock.............. $ 1 $ 1 $ 1 $ 1 $ 10 $ 14 $ 14
Average dividend rate .... 7.6% 7.6% 7.6% 7.6% 7.6% 7.6%
- ---------------------------------------------------------------------------------------------------------
EQUITY PRICE RISK
Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $148
million and $151 million as of December 31, 2002 and 2001, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$15 million reduction in fair value as of December 31, 2002 (see Note 1K -
Supplemental Cash Flows Information).
OUTLOOK
Our industry continues to transition to a more competitive
environment. In 2001, all our customers could select alternative energy
suppliers. We continue to deliver power to residential homes and businesses
through our existing distribution systems, which remain regulated. Customer
rates have been restructured into separate components to support customer
choice. In Ohio and Pennsylvania, 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
Beginning on January 1, 2001, Ohio customers were able to choose
their electricity suppliers. Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of our Ohio 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 for OE customers), and the customer receives a generation charge
from the alternative supplier. OE has continuing PLR responsibility to its
franchise customers through December 31, 2005. Regulatory assets are costs which
have been authorized by the Public Utilities Commission of Ohio (PUCO), PPUC 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. All of our regulatory assets are expected to continue to be recovered
under the provisions of our transition plan as discussed below. Our regulatory
assets are as follows:
REGULATORY ASSETS AS OF DECEMBER 31,
Company 2002 2001
------------------------------------------------------------
(IN MILLIONS)
OE.................................. $1,848.7 $2,025.4
Penn................................ 156.9 208.8
------------------------------------------------------------
Consolidated Total............... $2,005.6 $2,234.2
============================================================
8
The transition cost portion of rates provides for recovery of
certain amounts not otherwise recoverable in a competitive generation market
(such as regulatory assets). Transition costs are paid by all customers whether
or not they choose an alternative supplier. Under the PUCO-approved transition
plan, we assumed the risk of not recovering up to $250 million of transition
revenue if the rate of customers (excluding contracts and full-service accounts)
switching from our service to an alternative supplier did not reach 20% for any
consecutive twelve-month period by December 31, 2005 - the end of the market
development period. That goal was achieved in 2002. Accordingly, OE does not
believe that there will be any regulatory action reducing the recoverable
transition costs.
As part of our Ohio transition plan we are obligated to supply
electricity to customers who do not choose an alternative supplier. We are also
required to provided 560 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within our service area. Our
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in our franchise area. In 2003, the total peak load
forecasted for customers electing to stay with us, including the 560 MW of low
cost supply and the load served by our affiliate is 5,820 MW.
Environmental Matters
We believe we are in compliance with the current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 5C - Environmental
Matters). We continue to evaluate our compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W.H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act (CAA). The civil complaint against OE and Penn
requests installation of "best available control technology" as well as civil
penalties of up to $27,500 per day. On August 7, 2003, the United States
District Court for the Southern District of Ohio ruled that 11 projects
undertaken at the Sammis Plant between 1984 and 1998 required pre-construction
permits under the Clean Air Act. The ruling concludes the liability phase of the
case, which deals with applicability of Prevention of Significant Deterioration
provisions of the Clean Air Act. The remedy phase, which is currently scheduled
to be ready for trial beginning March 15, 2004, will address civil penalties and
what, if any, actions should be taken to further reduce emissions at the plant.
In the ruling, the Court indicated that the remedies it "may consider and impose
involved a much broader, equitable analysis, requiring the Court to consider air
quality, public health, economic impact, and employment consequences. The Court
may also consider the less than consistent efforts of the EPA to apply and
further enforce the Clean Air Act." The potential penalties that may be imposed,
as well as the capital expenditures necessary to comply with substantive
remedial measures that may be required, may have a material adverse impact on
the Company's financial condition. Management is unable to predict the ultimate
outcome of this matter.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on our earnings and
competitive position. These environmental regulations affect our earnings and
competitive position to the extent we compete with companies that are not
subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations. We
believe we are in material compliance with existing regulations, but are unable
to predict how and when applicable environmental regulations may change and
what, if any, the effects of any such change would be.
9
SIGNIFICANT ACCOUNTING POLICIES
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect our financial results. All of our assets
are subject to their own specific risks and uncertainties and are regularly
reviewed for impairment. Assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting those specific factors. Our more significant accounting policies are
described below.
Regulatory Accounting
The Companies are subject to regulation that sets the prices (rates)
we are permitted to charge our customers based on our costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio and Pennsylvania, a
significant amount of regulatory assets have been recorded. As of December 31,
2002, the Companies' regulatory assets totaled $2.0 billion. We continually
review these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet been billed
through the end of the year. The determination of unbilled revenues requires
management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy system
- Mix of kilowatt-hour usage by residential, commercial and industrial
customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions we make to the plans, and earnings on plan assets. Pension and
OPEB costs may also be affected by changes to key assumptions, including
anticipated rates of return on plan assets, the discount rates and health care
trend rates used in determining the projected benefit obligations and pension
and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently
available rates of return on high-quality fixed income investments expected to
be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, we reduced the assumed
discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75%
used in 2000.
Our assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by our pension trusts. The market values of our pension assets have been
affected by sharp declines in the equity markets since mid-2000. In 2002, 2001
and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our
pension costs in 2002 were computed assuming a 10.25% rate of return on plan
assets. As of December 31, 2002 the assumed return on plan assets was reduced to
9.00% based upon our
10
projection of future returns and pension trust investment allocation of
approximately 60% large cap equities, 10% small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, we will not be required to fund our pension plans in 2003. While OPEB
plan assets have also been affected by sharp declines in the equity market, the
impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates.
The effect on our SFAS 87 and 106 costs and liabilities from changes
in key assumptions are as follows:
INCREASE IN COSTS FROM ADVERSE CHANGES IN KEY ASSUMPTIONS
- --------------------------------------------------------------------------------
ASSUMPTION ADVERSE CHANGE PENSION OPEB TOTAL
- --------------------------------------------------------------------------------
(IN MILLIONS)
Discount rate.................. Decrease by 0.25% $ 0.6 $0.6 $ 1.2
Long-term return on assets..... Decrease by 0.25% $ 0.4 -- $ 0.4
Health care trend rate......... Increase by 1% na $1.6 $ 1.6
INCREASE IN MINIMUM LIABILITY
Discount rate.................. Decrease by 0.25% $ 13.3 na $13.3
- --------------------------------------------------------------------------------
As a result of the reduced market value of our pension plan assets,
we were required to recognize an additional minimum liability as prescribed by
SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement
Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of
$57.2 million and established a minimum liability of $76.1 million, recording an
intangible asset of $23.2 million and reducing OCI by $64.6 million (recording a
related deferred tax benefit of $45.5 million). The charge to OCI will reverse
in future periods to the extent the fair value of trust assets exceed the
accumulated benefit obligation. The amount of pension liability recorded as of
December 31, 2002, increased due to the lower discount rate assumed and reduced
market value of plan assets as of December 31, 2002. Our non-cash, pre-tax
pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by
$9 million and $3 million, respectively - a total of $12 million in 2003 as
compared to 2002.
Ohio Transition Cost Amortization
In developing FirstEnergy's restructuring plan, the PUCO determined
allowable transition costs based on amounts recorded on the EUOC's regulatory
books. These costs exceeded those deferred or capitalized on FirstEnergy's
balance sheet prepared under GAAP since they included certain costs which have
not yet been incurred. FirstEnergy uses an effective interest method for
amortizing its transition costs, often referred to as a "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for each respective company. In
computing the transition cost amortization, FirstEnergy includes only the
portion of the transition revenues associated with transition costs included on
the balance sheet prepared under GAAP. Revenues collected for the off balance
sheet costs and the return associated with these costs are recognized as income
when received.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset, is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, we recognize a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
SFAS 143, "Accounting for Asset Retirement Obligations"
In June 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 143, "Accounting for Asset Retirement Obligations." The new statement
provides accounting standards for retirement obligations associated with
tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143
requires that the fair value of a liability for an asset retirement obligation
be recorded in the period in which it is incurred. The associated asset
retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and
11
the present value of the asset retirement liability increases, resulting in a
period expense. However, rate-regulated entities may recognize regulatory assets
or liabilities if the criteria for such treatment are met. Upon retirement, a
gain or loss would be recorded if the cost to settle the retirement obligation
differs from the carrying amount.
We have identified applicable legal obligations as defined under the
new standard, principally for nuclear power plant decommissioning. Upon adoption
of SFAS 143 in January 2003, asset retirement costs of $134 million were
recorded as part of the carrying amount of the related long-lived asset, offset
by accumulated depreciation of $25 million. Due to the increased carrying
amount, the related long-lived assets were tested for impairment in accordance
with SFAS 144. No impairment was indicated. The asset retirement liability at
the date of adoption was $298 million. As of December 31, 2002, the Companies
had recorded decommissioning liabilities of $281 million. The change in the
estimated liabilities resulted from changes in methodology and various
assumptions, including changes in the projected dates for decommissioning.
Management expects that substantially all nuclear decommissioning
costs for Penn will be recoverable through its regulated rates. Therefore, Penn
will recognize a regulatory liability of $69 million upon adoption of SFAS 143
for the transition amounts related to establishing the asset retirement
obligations for nuclear decommissioning. The remaining cumulative effect
adjustment to recognize the undepreciated asset retirement cost and the asset
retirement liability offset by the reversal of the previously recorded
decommissioning liabilities was a $23 million increase to income ($14 million
net of tax).
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities"
This statement, which was issued by the FASB in July 2002, requires
the recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (Including Certain
Costs Incurred in a Restructuring)." This new standard was effective for exit
and disposal activities initiated after December 31, 2002. Since it is applied
prospectively, there will be no impact upon adoption. However, SFAS 146 could
change the timing and amount of costs recognized in connection with future exit
or disposal activities.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness
of Others - an interpretation of FASB Statements No. 5, 57, and 107 and
rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation
identifies minimum guarantee disclosures required for annual periods ending
after December 15, 2002. It also clarifies that providers of guarantees must
record the fair value of those guarantees at their inception. This accounting
guidance is applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. We do not believe that implementation of FIN 45 will be
material but we will continue to evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (OE's third quarter of 2003). The
FASB also identified transitional disclosure provisions for all financial
statements issued after January 31, 2003.
OE currently has transactions which may fall within the scope of
this interpretation and which are reasonably possible of meeting the definition
of a VIE in accordance with FIN 46. OE currently consolidates the majority of
these entities and believes it will continue to consolidate following the
adoption of FIN 46. In addition to the entities OE is currently consolidating OE
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $11.6 million.
12
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 is effective for financial
instruments entered into or modified after May 31, 2003 and is effective at the
beginning of the first interim period beginning after June 15, 2003 (OE's third
quarter of 2003) for all other financial instruments.
OE did not enter into or modify any financial instruments within the
scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1,
2003, OE expects to classify as debt the preferred stock of consolidated
subsidiaries subject to mandatory redemptions with a carrying value of
approximately $13.5 million as of June 30, 2003. Subsidiary preferred dividends
on OE's Consolidated Statements of Income are currently included in net interest
charges. Therefore, the application of SFAS 150 will not require the
reclassification of such preferred dividends to net interest charges.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003 which would correspond to OE's
fourth quarter of 2003. The issue supersedes earlier DIG Issue C11,
"Interpretation of Clearly and Closely Related in Contracts That Qualify for the
Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance
regarding when the presence in a contract of a general index, such as the
Consumer Price Index, would prevent that contract from qualifying for the normal
purchases and normal sales (NPNS) exception under SFAS 133, as amended, and
therefore exempt from the mark-to-market treatment of certain contracts. DIG
Issue C20 is to be applied prospectively to all existing contracts as of its
effective date and for all future transactions. If it is determined under DIG
Issue C20 guidance that the NPNS exception was claimed for an existing contract
that was not eligible for this exception, the contract will be recorded at fair
value, with a corresponding adjustment of net income as the cumulative effect of
a change in accounting principle in the fourth quarter of 2003. OE is currently
assessing the new guidance and has not yet determined the impact on its
financial statements.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when
arrangements contain a lease. Based on the EITF consensus, an arrangement
contains a lease if (1) it identifies specific property, plant or equipment
(explicitly or implicitly), and (2) the arrangement transfers the right to the
purchaser to control the use of the property, plant or equipment. The consensus
will be applied prospectively to arrangements committed to, modified or acquired
through a business combination, beginning in the third quarter of 2003. OE is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
13
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN THOUSANDS)
OPERATING REVENUES (NOTE 1J)............................................ $2,948,675 $3,056,464 $2,726,708
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1J)................................... 986,737 1,096,317 418,790
Nuclear operating costs.............................................. 352,129 381,047 366,387
Other operating costs (Note 1J)...................................... 364,436 313,177 456,246
---------- ---------- ----------
Total operation and maintenance expenses........................... 1,703,302 1,790,541 1,241,423
Provision for depreciation and amortization.......................... 385,520 424,920 578,679
General taxes........................................................ 177,021 153,506 225,849
Income taxes......................................................... 229,001 220,678 198,436
---------- ---------- ----------
Total operating expenses and taxes................................. 2,494,844 2,589,645 2,244,387
---------- ---------- ----------
OPERATING INCOME........................................................ 453,831 466,819 482,321
OTHER INCOME (NOTE 1J).................................................. 42,859 68,681 55,976
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES...................................... 496,690 535,500 538,297
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt........................................... 119,123 150,632 165,409
Allowance for borrowed funds used during
construction and capitalized interest.............................. (3,639) (2,602) (9,523)
Other interest expense............................................... 14,598 22,754 31,451
Subsidiaries' preferred stock dividend requirements.................. 10,449 14,504 14,504
---------- ---------- ----------
Net interest charges............................................... 140,531 185,288 201,841
---------- ---------- ----------
NET INCOME.............................................................. 356,159 350,212 336,456
PREFERRED STOCK DIVIDEND REQUIREMENTS................................... 6,510 10,702 11,124
---------- ---------- ----------
EARNINGS ON COMMON STOCK................................................ $ 349,649 $ 339,510 $ 325,332
========== ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
14
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service...................................................................... $4,989,056 $4,979,807
Less-Accumulated provision for depreciation..................................... 2,552,007 2,461,972
---------- ----------
2,437,049 2,517,835
---------- ----------
Construction work in progress-
Electric plant................................................................ 122,741 87,061
Nuclear Fuel.................................................................. 23,481 11,822
---------- ----------
146,222 98,883
---------- ----------
2,583,271 2,616,718
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust (Note 2)..................................................... 402,565 429,040
Letter of credit collateralization (Note 2)..................................... 277,763 277,763
Nuclear plant decommissioning trusts............................................ 293,190 277,337
Long-term notes receivable from associated companies (Note 3B).................. 503,827 505,028
Other (Note 1I)................................................................. 74,220 303,409
---------- ----------
1,551,565 1,792,577
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents....................................................... 20,512 4,588
Receivables-
Customers (less accumulated provisions of $5,240,000 and $4,522,000,
respectively, for uncollectible accounts)................................... 296,548 311,744
Associated companies.......................................................... 592,218 523,884
Other (less accumulated provision of $1,000,000 for uncollectible accounts
at both dates).............................................................. 30,057 41,611
Notes receivable from associated companies...................................... 437,669 108,593
Materials and supplies, at average cost-
Owned......................................................................... 58,022 53,900
Under consignment............................................................. 19,753 13,945
Prepayments and other........................................................... 11,804 50,541
---------- ----------
1,466,583 1,108,806
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................... 2,005,554 2,234,227
Property taxes.................................................................. 59,035 58,244
Unamortized sale and leaseback costs............................................ 72,294 75,105
Other........................................................................... 51,739 30,276
---------- ----------
2,188,622 2,397,852
---------- ----------
$7,790,041 $7,915,953
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity..................................................... $2,839,255 $2,671,001
Preferred stock not subject to mandatory redemption............................. 60,965 160,965
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption........................................... 39,105 39,105
Subject to mandatory redemption............................................... 13,500 14,250
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures............... -- 120,000
Long-term debt.................................................................. 1,219,347 1,614,996
---------- ----------
4,172,172 4,620,317
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock............................ 563,267 576,962
Short-term borrowings (Note 4)-
Associated companies.......................................................... 225,345 26,076
Other......................................................................... 182,317 219,750
Accounts payable-
Associated companies.......................................................... 145,981 110,784
Other......................................................................... 18,015 19,819
Accrued taxes................................................................... 466,064 258,831
Accrued interest................................................................ 28,209 33,053
Other........................................................................... 74,562 63,140
---------- ----------
1,703,760 1,308,415
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes............................................... 1,017,629 1,175,395
Accumulated deferred investment tax credits..................................... 88,449 99,193
Nuclear plant decommissioning costs............................................. 280,858 276,500
Retirement benefits............................................................. 247,531 166,594
Other........................................................................... 279,642 269,539
---------- ----------
1,914,109 1,987,221
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5).................................................................
---------- ----------
$7,790,041 $7,915,953
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
15
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
AS OF DECEMBER 31, 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 175,000,000 shares-100 shares outstanding...... $2,098,729 $2,098,729
Accumulated other comprehensive loss (Note 3G)............................................. (59,495) --
Retained earnings (Note 3A)................................................................ 800,021 572,272
---------- ----------
Total common stockholder's equity...................................................... 2,839,255 2,671,001
---------- ----------
NUMBER OF SHARES OPTIONAL
OUTSTANDING REDEMPTION PRICE
------------------ --------------------
2002 2001 PER SHARE AGGREGATE
------- --------- --------- ---------
PREFERRED STOCK (NOTE 3D):
Cumulative, $100 par value-
Authorized 6,000,000 shares
Not Subject to Mandatory Redemption:
3.90%..................................... 152,510 152,510 $103.63 $15,804 15,251 15,251
4.40%..................................... 176,280 176,280 108.00 19,038 17,628 17,628
4.44%..................................... 136,560 136,560 103.50 14,134 13,656 13,656
4.56%..................................... 144,300 144,300 103.38 14,917 14,430 14,430
------- --------- ------- --------- ---------
609,650 609,650 63,893 60,965 60,965
------- --------- ------- --------- ---------
Cumulative, $25 par value-
Authorized 8,000,000 shares
Not Subject to Mandatory Redemption:
7.75%..................................... -- 4,000,000 -- -- -- 100,000
------- --------- ------- --------- ---------
Total Not Subject to
Mandatory Redemption.................. 609,650 4,609,650 $63,893 60,965 160,965
======= ========= ======= --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARY (NOTE 3D):
PENNSYLVANIA POWER COMPANY-
Cumulative, $100 par value-
Authorized 1,200,000 shares
Not Subject to Mandatory Redemption:
4.24%..................................... 40,000 40,000 $103.13 $ 4,125 4,000 4,000
4.25%..................................... 41,049 41,049 105.00 4,310 4,105 4,105
4.64%..................................... 60,000 60,000 102.98 6,179 6,000 6,000
7.75%..................................... 250,000 250,000 -- -- 25,000 25,000
------- --------- ------- --------- ---------
Total Not Subject to Mandatory
Redemption............................ 391,049 391,049 $14,614 39,105 39,105
======= ========= ======= --------- ---------
Subject to Mandatory Redemption (Note 3E):
7.625%.................................... 142,500 150,000 103.81 $14,793 14,250 15,000
Redemption Within One Year................ (750) (750)
------- --------- ------- --------- ---------
Total Subject to Mandatory Redemption 142,500 150,000 $14,793 13,500 14,250
======= ========= ======= ========= =========
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY COMPANY SUBORDINATED
DEBENTURES:
Cumulative, $25 par value-
Authorized 4,800,000 shares
Subject to Mandatory Redemption:
9.00%..................................... -- 4,800,000 -- $ -- -- 120,000
======= ========= ======= --------- ----------
16
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONT'D)
AS OF DECEMBER 31, 2002 2001 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN THOUSANDS)
LONG-TERM DEBT (NOTE 3F):
FIRST MORTGAGE BONDS:
OHIO EDISON COMPANY- PENNSYLVANIA POWER COMPANY-
7.375% due 2002................. -- 120,000 9.740% due 2003-2019...... 16,591 17,565
7.500% due 2002................. -- 34,265 7.500% due 2003........... 40,000 40,000
8.250% due 2002................. -- 125,000 6.375% due 2004........... 20,500 20,500
8.625% due 2003................. 150,000 150,000 6.625% due 2004........... 14,000 14,000
6.875% due 2005................. 80,000 80,000 8,500% due 2022........... 27,250 27,250
8.750% due 2022................. 50,960 50,960 7.625% due 2023........... 6,500 6,500
7.625% due 2023................. 75,000 75,000 ------- -------
7.875% due 2023................. 93,500 93,500
-------- --------
Total first mortgage bonds........... 449,460 728,725
------- ------- 124,841 125,815 574,301 854,540
------- ------- ---------- ----------
SECURED NOTES:
OHIO EDISON COMPANY- PENNSYLVANIA POWER COMPANY-
7.930% due 2002................. -- 2,360 5.400% due 2013........... 1,000 1,000
7.680% due 2005................. 162,504 200,000 5.400% due 2017........... 10,600 10,600
*1.300% due 2015................. 19,000 19,000 *1.350% due 2017........... 17,925 17,925
6.750% due 2015................. 40,000 40,000 5.900% due 2018........... 16,800 16,800
7.050% due 2020................. 60,000 60,000 *1.350% due 2021........... 14,482 14,482
*1.350% due 2021................. 443 443 6.150% due 2023........... 12,700 12,700
5.375% due 2028................. 13,522 13,522 *1.600% due 2027........... 10,300 10,300
5.625% due 2029................. 50,000 50,000 6.450% due 2027........... -- 14,500
5.950% due 2029................. 56,212 56,212 5.375% due 2028........... 1,734 1,734
*1.300% due 2030................. 60,400 60,400 5.450% due 2028........... 6,950 6,950
*1.350% due 2031................. 69,500 69,500 6.000% due 2028........... 14,250 14,250
*1.350% due 2033................. 57,100 57,100 5.950% due 2029........... 238 238
------- -------
5.450% due 2033................. 14,800 14,800
Limited Partnerships-...........
7.41% weighted average..........
interest rate due 2003-2010... 29,513 35,015
------- -------
632,994 678,352 106,979 121,479 739,973 799,831
------- ------- ------- ------- ---------- ----------
OES FUEL-
2.72% weighted average interest
as of December 31, 2001....... -- 81,515
---------- ----------
Total secured notes.................. 739,973 881,346
---------- ----------
UNSECURED NOTES:
OHIO EDISON COMPANY- PENNSYLVANIA POWER COMPANY-
*1.500% due 2014................. 50,000 50,000 *5.900% due 2033........... 5,200 5,200
*4.850% due 2015................. 50,000 50,000 *3.850% due 2029........... 14,500 --
------- -------
*5.800% due 2016................. 47,725 47,725
*1.750% due 2018................. 33,000 33,000
*1.750% due 2018................. 23,000 23,000
*1.600% due 2023................. 50,000 50,000
*4.300% due 2033................. 50,000 50,000
*4.650% due 2033................. 108,000 108,000
*4.400% due 2033................. 30,000 30,000
------- -------
Total unsecured notes................ 441,725 441,725 19,700 5,200 461,425 446,925
------- ------- ------- ------- ---------- ----------
Capital lease obligations (Note 2)... 8,249 10,718
---------- ----------
Net unamortized discount on debt..... (2,084) (2,321)
---------- ----------
Long-term debt due within one year... (562,517) (576,212)
---------- ----------
Total long-term debt................. 1,219,347 1,614,996
---------- ----------
TOTAL CAPITALIZATION................. $4,172,172 $4,620,317
========== ==========
* Denotes variable rate issue with December 31, 2002 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
17
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
ACCUMULATED
OTHER
COMPREHENSIVE NUMBER CARRYING COMPREHENSIVE RETAINED
INCOME OF SHARES VALUE INCOME (LOSS) EARNINGS
------------- --------- -------- ------------- --------
RESTATED RESTATED RESTATED
(SEE NOTE 1(M)) (SEE NOTE 1(M))
(DOLLARS IN THOUSANDS)
Balance, January 1, 2000............................ 100 $2,098,729 $ -- $525,731
Net income....................................... $336,456 336,456
========
Cash dividends on preferred stock................ (11,124)
Cash dividends on common stock................... (392,800)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000.......................... 100 2,098,729 -- 458,263
Net income....................................... $350,212 350,212
========
Cash dividends on preferred stock................ (10,703)
Cash dividends on common stock................... (225,500)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001.......................... 100 2,098,729 -- 572,272
Net income....................................... $356,159 356,159
Minimum liability for unfunded retirement
benefits, net of $(45,525,000) of income taxes (64,585) (64,585)
Unrealized gain on investments, net of
$3,582,000 of income taxes..................... 5,090 5,090
----------
Comprehensive income............................. $296,664
========
Cash dividends on preferred stock................ (6,510)
Cash dividends on common stock................... (121,900)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002.......................... 100 $2,098,729 $(59,495) $800,021
===============================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
NOT SUBJECT TO SUBJECT TO
MANDATORY REDEMPTION MANDATORY REDEMPTION
-------------------- --------------------
NUMBER PAR NUMBER PAR
OF SHARES VALUE OF SHARES VALUE
--------- ----- --------- -----
(DOLLARS IN THOUSANDS)
Balance, January 1, 2000......... 5,000,699 $ 200,070 5,050,000 $ 145,000
Redemptions-
8.45% Series................ (50,000) (5,000)
------------------------------------------------------------------------------------
Balance, December 31, 2000....... 5,000,699 200,070 5,000,000 140,000
Redemptions-
8.45% Series................ (50,000) (5,000)
------------------------------------------------------------------------------------
Balance, December 31, 2001....... 5,000,699 200,070 4,950,000 135,000
Redemptions -
7.75% Series................ (4,000,000) (100,000)
9.00% Series................ (4,800,000) (120,000)
7.625% Series................ (7,500) (750)
------------------------------------------------------------------------------------
Balance, December 31, 2002....... 1,000,699 $ 100,070 142,500 $ 14,250
====================================================================================
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
18
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income............................................................... $ 356,159 $ 350,212 $ 336,456
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization......................... 385,520 424,920 578,679
Nuclear fuel and lease amortization................................. 47,597 45,417 52,232
Deferred income taxes, net.......................................... (61,987) (63,945) (110,038)
Investment tax credits, net......................................... (13,732) (13,346) (25,035)
Receivables......................................................... (41,584) (61,246) (279,575)
Materials and supplies.............................................. (9,930) 64,177 (7,625)
Accounts payable.................................................... 182,229 (53,588) 70,089
Other (Note 7)...................................................... 212,929 (24,912) 8,753
---------- --------- ---------
Net cash provided from operating activities....................... 1,057,201 667,689 623,936
---------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt........................................................ 14,500 111,584 207,283
Short-term borrowings, net............................................ 161,836 -- --
Redemptions and Repayments-
Preferred stock....................................................... (220,750) (5,000) (5,000)
Long-term debt........................................................ (425,742) (233,158) (485,178)
Short-term borrowings, net............................................ -- (69,606) (42,864)
Dividend Payments-
Common stock.......................................................... (121,900) (225,500) (392,800)
Preferred stock....................................................... (6,510) (10,703) (11,124)
---------- --------- ---------
Net cash used for financing activities............................ (598,566) (432,383) (729,683)
---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions....................................................... (148,967) (145,427) (279,508)
Loans to associated companies............................................ (328,989) (262,076) (206,901)
Loan payments from associated companies.................................. 1,113 1,032 --
Sale of assets to associated companies................................... -- 154,596 531,633
Other (Note 7)........................................................... 34,132 2,888 (8,383)
---------- --------- ---------
Net cash provided from (used for) investing activities............ (442,711) (248,987) 36,841
---------- --------- ---------
Net increase (decrease) in cash and cash equivalents..................... 15,924 (13,681) (68,906)
Cash and cash equivalents at beginning of year........................... 4,588 18,269 87,175
---------- --------- ---------
Cash and cash equivalents at end of year................................. $ 20,512 $ 4,588 $ 18,269
========== ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)............................... $ 118,535 $ 180,263 $ 183,117
========== ========= =========
Income taxes........................................................ $ 126,558 $ 240,882 $ 305,644
========== ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
19
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN THOUSANDS)
GENERAL TAXES:
Real and personal property............................................. $ 65,709 $ 45,132 $ 103,741
State gross receipts*.................................................. 18,516 45,271 104,851
Ohio kilowatt-hour excise*............................................. 85,762 55,795 --
Social security and unemployment....................................... 5,438 4,159 11,964
Other.................................................................. 1,596 3,149 5,293
----------- ----------- -----------
Total general taxes............................................... $ 177,021 $ 153,506 $ 225,849
=========== =========== ===========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal............................................................. $ 280,587 $ 265,305 $ 329,616
State............................................................... 55,796 51,121 18,037
----------- ----------- -----------
336,383 316,426 347,653
----------- ----------- -----------
Deferred, net-
Federal............................................................. (44,552) (56,105) (102,692)
State............................................................... (22,184) (7,840) (7,346)
----------- ----------- -----------
(66,736) (63,945) (110,038)
----------- ----------- -----------
Investment tax credit amortization..................................... (13,732) (13,346) (25,035)
----------- ----------- -----------
Total provision for income taxes.................................. $ 255,915 $ 239,135 $ 212,580
=========== =========== ===========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income....................................................... $ 229,001 $ 220,678 $ 198,436
Other income........................................................... 26,914 18,457 14,144
----------- ----------- -----------
Total provision for income taxes.................................. $ 255,915 $ 239,135 $ 212,580
=========== =========== ===========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes.......................... $ 612,074 $ 589,347 $ 549,036
=========== =========== ===========
Federal income tax expense at statutory rate........................... $ 214,225 $ 206,271 $ 192,163
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits.............................. (13,732) (13,346) (25,035)
State income taxes, net of federal income tax benefit............... 21,848 28,133 6,949
Amortization of tax regulatory assets............................... 30,659 32,020 39,746
Other, net.......................................................... 2,915 (13,943) (1,243)
----------- ----------- -----------
Total provision for income taxes.................................. $ 255,915 $ 239,135 $ 212,580
=========== =========== ===========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences............................................. $ 397,930 $ 374,138 $ 377,521
Allowance for equity funds used during construction.................... 34,407 36,587 62,604
Competitive transition charge.......................................... 527,502 675,652 755,607
Customer receivables for future income taxes........................... 49,486 54,600 68,624
Deferred sale and leaseback costs...................................... (71,830) (77,099) (30,151)
Unamortized investment tax credits..................................... (33,421) (38,680) (39,369)
Deferred gain for asset sale to affiliated company..................... 70,812 85,311 73,312
Other comprehensive income............................................. (41,570) -- --
Other (Note 7)......................................................... 84,313 64,886 30,697
----------- ----------- -----------
Net deferred income tax liability................................. $ 1,017,629 $ 1,175,395 $ 1,298,845
=========== =========== ===========
* Collected from customers through regulated rates and included in revenue on
the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include Ohio Edison Company
(Company) and its wholly owned subsidiaries. Pennsylvania Power Company (Penn)
is the Company's principal operating subsidiary. All significant intercompany
transactions have been eliminated. The Company is a wholly owned subsidiary of
FirstEnergy Corp. FirstEnergy holds directly all of the issued and outstanding
common shares of its principal electric utility operating subsidiaries,
including, the Company and The Cleveland Electric Illuminating Company (CEI),
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). JCP&L, Met-Ed and Penelec
were formerly wholly owned subsidiaries of GPU, Inc. which merged with
FirstEnergy on November 7, 2001.
The Company and Penn (Companies) follow the accounting policies and
practices prescribed by the Securities and Exchange Commission (SEC), the Public
Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission
(PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States (GAAP) requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ from these estimates.
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, after
eliminating the effects of intercompany transactions. Non-majority owned
investments, including investments in limited liability companies, partnerships
and joint ventures, are accounted for under the equity method when the Company
is able to influence their financial or operating policies. Investments in
corporations resulting in voting control of 20% or more are presumed to be
equity method investments. Limited partnerships are evaluated in accordance with
SEC Staff D-46, "Accounting for Limited Partnership Investments" and American
Institute of Certified Public Accountants (AICPA) Statement of Position (SOP)
78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to
5 percent threshold for the presumption of influence. For all remaining
investments (excluding those within the scope of Statement of Financial
Accounting Standards (SFAS) 115, the Company applies the cost method.
(B) REVENUES-
The Companies' principal business is providing electric service to
customers in central and northeastern Ohio and western Pennsylvania. The
Companies' retail customers are metered on a cycle basis. Revenue is recognized
for unbilled electric service through the end of the year.
Receivables from customers include sales to residential, commercial
and industrial customers located in the Companies' service area and sales to
wholesale customers. There was no material concentration of receivables at
December 31, 2002 or 2001, with respect to any particular segment of the
Companies' customers.
(C) REGULATORY PLANS-
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, CEI and TE 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 generation business
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 the Company's 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 $1.0 billion net of deferred income taxes with
recovery through no later than 2006 for the Company except where a longer period
of recovery is provided for in the settlement agreement. The generation-related
transition costs include $1.0 billion, net of deferred income taxes of impaired
generating assets recognized as regulatory assets as described further below and
$1.2 billion, net of deferred income taxes of above market operating lease
costs.
21
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 560 megawatts (MW) of generation capacity through 2005 at
established prices for sales to the Company's retail customers. Customer prices
are frozen through the five-year market development period except for certain
limited statutory exceptions, including the 5% reduction referred to above. In
February 2003, the Company was authorized increases in annual revenues
aggregating approximately $41 million to recover its higher tax costs resulting
from the Ohio deregulation legislation.
The Company's customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
transition cost recovery period. If the customer shopping goals established in
the agreement had not been achieved by the end of 2005, the transition cost
recovery period could have been shortened for the Company to reduce recovery by
as much as $250 million. The Company achieved its required 20% customer shopping
goals in 2002. Accordingly, the Company believes that there will be no
regulatory action reducing the recoverable transition costs.
Pennsylvania enacted its electric utility competition law in 1996
with the phase-in of customer choice for generation suppliers completed as of
January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for
Penn, which essentially resulted in the deregulation of Penn's generation
business.
The application of SFAS 71 has been discontinued with respect to the
Companies' generation operations. The SEC issued interpretive guidance regarding
asset impairment measurement concluding that any supplemental regulated cash
flows such as a competitive transition charge (CTC) 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, $1.2 billion of impaired plant investments
were recognized by the Company as regulatory assets recoverable as transition
costs through future regulatory cash flows and $227 million were recognized for
Penn related to its 1998 impairment of its nuclear generating unit investments
to be recovered through a CTC over a seven-year transition period.
Net assets included in utility plant relating to the operations for
which the application of SFAS 71 was discontinued, compared to the respective
company's total assets as of December 31, 2002 were $947 million and $7.16
billion, respectively, for the Company and $82 million and $908 million,
respectively, for Penn.
(D) UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction (except for
the Companies' nuclear generating units which were adjusted to fair value
including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs. The Companies' accounting
policy for planned major maintenance projects is to expense costs and recognize
liabilities as they are incurred.
The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annual composite rate for the Company's electric plant was approximately
2.7% in 2002 and 2001, and 2.8% in 2000. The annual composite rate for Penn's
electric plant was approximately 2.9% in 2002 and 2001, and 2.6% in 2000.
Annual depreciation expense in 2002 included approximately $31.5
million for future decommissioning costs applicable to the Companies' ownership
and leasehold interests in three nuclear generating units (Beaver Valley Units 1
and 2 and Perry Unit 1). The Companies' share of the future obligation to
decommission these units is approximately $874 million in current dollars and
(using a 4.0% escalation rate) approximately $1.9 billion in future dollars. The
estimated obligation and the escalation rate were developed based on site
specific studies. Payments for decommissioning are expected to begin in 2016,
when actual decommissioning work is expected to begin. The Companies have
recovered approximately $160 million for decommissioning through their electric
rates from customers through December 31, 2002. The Companies have also
recognized an estimated liability of approximately $10.5 million related to
decontamination and decommissioning of nuclear enrichment facilities operated by
the United States Department of Energy, as required by the Energy Policy Act of
1992.
In June 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 143, "Accounting for Asset Retirement Obligations". The new statement
provides accounting standards for retirement obligations associated with
tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143
requires that the fair value of a liability for an asset retirement obligation
be recorded in the period in which it is incurred. The associated asset
retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. However, rate-regulated entities may recognize a regulatory asset or
liability if the criteria for such treatment are met. Upon retirement, a gain or
loss would be recorded if the cost to settle the retirement obligation differs
from the carrying amount.
22
The Companies have identified applicable legal obligations as
defined under the new standard, principally for nuclear power plant
decommissioning. Upon adoption of SFAS 143, asset retirement costs of $134
million were recorded as part of the carrying amount of the related long-lived
asset, offset by accumulated depreciation of $25 million. Due to the increased
carrying amount, the related long-lived assets were tested for impairment in
accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived
Assets". No impairment was indicated.
The asset retirement liability at the date of adoption was $298
million. As of December 31, 2002, the Companies have recorded decommissioning
liabilities of $281 million. The change in the estimated liabilities resulted
from changes in methodology and various assumptions, including changes in the
projected dates for decommissioning.
Management expects that the ultimate nuclear decommissioning costs
for Penn will be tracked and recovered through its regulated rates. Therefore,
Penn recognized a regulatory liability of $69 million upon adoption of SFAS 143
for the transition amounts related to establishing the asset retirement
obligations for nuclear decommissioning. The remaining cumulative effect
adjustment to recognize the undepreciated asset retirement cost and the asset
retirement liability offset by the reversal of the previously recorded
decommissioning liabilities was a $23 million increase to income ($14 million
net of tax).
(E) COMMON OWNERSHIP OF GENERATING FACILITIES-
The Companies, together with CEI and TE, 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 Companies' portions of operating
expenses associated with jointly owned facilities are included in the
corresponding operating expenses on the Consolidated Statements of Income. The
amounts reflected on the Consolidated Balance Sheet under utility plant at
December 31, 2002 include the following:
COMPANIES'
UTILITY ACCUMULATED CONSTRUCTION OWNERSHIP/
PLANT PROVISION FOR WORK IN LEASEHOLD
GENERATING UNITS IN SERVICE DEPRECIATION PROGRESS INTEREST
- --------------------------------------------------------------------------------------
(IN MILLIONS)
W. H. Sammis #7.............. $ 336.1 $ 165.3 $ -- 68.80%
Bruce Mansfield #1,
#2 and #3................. 987.6 534.1 3.4 67.18%
Beaver Valley
#1 and #2................. 64.8 14.8 67.7 77.81%
Perry........................ 324.9 302.4 6.4 35.24%
- --------------------------------------------------------------------------------------
Total..................... $1,713.4 $1,016.6 $77.5
======================================================================================
(F) NUCLEAR FUEL-
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. The
Companies amortize the cost of nuclear fuel based on the rate of consumption.
(G) STOCK-BASED COMPENSATION-
If 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 3c). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the
fair value method, a higher value would have been assigned to the options
granted. The weighted average assumptions used in valuing the options and their
resulting estimated fair values would be as follows:
2002 2001 2000
------------------------------------------------------------
Valuation assumptions:
Expected option term (years).... 8.1 8.3 7.6
Expected volatility............. 23.31% 23.45% 21.77%
Expected dividend yield......... 4.36% 5.00% 6.68%
Risk-free interest rate......... 4.60% 4.67% 5.28%
Fair value per option............. $6.45 $4.97 $2.86
------------------------------------------------------------
The effects of applying fair value accounting to the Companies'
stock options would not materially effect net income.
23
(H) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and accounting
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred income taxes. Deferred income tax liabilities
related to tax and accounting basis differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid. The
Companies are included in FirstEnergy's consolidated federal income tax return.
The consolidated tax liability is allocated on a "stand-alone" company basis,
with the Companies recognizing any tax losses or credits they contributed to the
consolidated return.
(I) RETIREMENT BENEFITS-
FirstEnergy's trusteed, noncontributory defined benefit pension plan
covers almost all of the Companies' full-time employees. Upon retirement,
employees receive a monthly pension based on length of service and compensation.
On December 31, 2001, the GPU pension plans were merged with the FirstEnergy
plan. The Companies use the projected unit credit method for funding purposes
and were not required to make pension contributions during the three years ended
December 31, 2002. The assets of the FirstEnergy pension plan consist primarily
of common stocks, United States government bonds and corporate bonds.
The Companies provide 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 Companies pay insurance
premiums to cover a portion of these benefits in excess of set limits; all
amounts up to the limits are paid by the Companies. The Companies recognize the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits.
As a result of the reduced market value of FirstEnergy's pension
plan assets, FirstEnergy was required to recognize an additional minimum
liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about
Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's
accumulated benefit obligation of $3.438 billion exceeded the fair value of plan
assets ($2.889 billion) resulting in a minimum pension liability of $548.6
million. FirstEnergy eliminated its prepaid pension asset of $286.9 million
(Companies - $57.2 million) and established a minimum liability of $548.6
million (Companies - $76.1 million), recording an intangible asset of $78.5
million (Companies - $23.2 million) and reducing OCI by $444.2 million
(Companies - $64.6 million) (recording a related deferred tax asset of $312.8
million (Companies - $45.5 million)). The charge to OCI will reverse in future
periods to the extent the fair value of trust assets exceed the accumulated
benefit obligation. The amount of pension liability recorded as of December 31,
2002, increased due to the lower discount rate and asset returns assumed as of
December 31, 2002.
24
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
OTHER
PENSION BENEFITS POSTRETIREMENT BENEFITS
--------------------- -----------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------
(IN MILLIONS)
Change in benefit obligation:
Benefit obligation as of January 1............ $3,547.9 $1,506.1 $1,581.6 $ 752.0
Service cost.................................. 58.8 34.9 28.5 18.3
Interest cost................................. 249.3 133.3 113.6 64.4
Plan amendments............................... -- 3.6 (121.1) --
Actuarial loss................................ 268.0 123.1 440.4 73.3
Voluntary early retirement program............ -- -- -- 2.3
GPU acquisition............................... (11.8) 1,878.3 110.0 716.9
Benefits paid................................. (245.8) (131.4) (83.0) (45.6)
- -------------------------------------------------------------------------------------------------
Benefit obligation as of December 31.......... 3,866.4 3,547.9 2,070.0 1,581.6
- -------------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1..... 3,483.7 1,706.0 535.0 23.0
Actual return on plan assets.................. (348.9) 8.1 (57.1) 12.7
Company contribution.......................... -- -- 37.9 43.3
GPU acquisition............................... -- 1,901.0 -- 462.0
Benefits paid................................. (245.8) (131.4) (42.5) (6.0)
- -------------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31... 2,889.0 3,483.7 473.3 535.0
- -------------------------------------------------------------------------------------------------
Funded status of plan......................... (977.4) (64.2) (1,596.7) (1,046.6)
Unrecognized actuarial loss................... 1,185.8 222.8 751.6 212.8
Unrecognized prior service cost............... 78.5 87.9 (106.8) 17.7
Unrecognized net transition obligation........ -- -- 92.4 101.6
- -------------------------------------------------------------------------------------------------
Net amount recognized......................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
=================================================================================================
Amounts recognized on the Consolidated
Balance Sheets consist of:
Prepaid (accrued) benefit cost................ $ (548.6) $ 246.5 $ (859.5) $ (714.5)
Intangible asset.............................. 78.5 -- -- --
Accumulated other comprehensive loss.......... 757.0 -- -- --
- -------------------------------------------------------------------------------------------------
Net amount recognized......................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
=================================================================================================
Companies' share of net amount
recognized.................................. $ 57.2 $ 210.7 $ (171.0) $ (165.8)
=================================================================================================
Assumptions used as of December 31:
Discount rate................................. 6.75% 7.25% 6.75% 7.25%
Expected long-term return on plan assets...... 9.00% 10.25% 9.00% 10.25%
Rate of compensation increase................. 3.50% 4.00% 3.50% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2002 were computed as follows:
OTHER
PENSION BENEFITS POSTRETIREMENT BENEFITS
---------------------------- -----------------------
2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Service cost...................................... $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3
Interest cost..................................... 249.3 133.3 104.8 113.6 64.4 45.7
Expected return on plan assets.................... (346.1) (204.8) (181.0) (51.7) (9.9) (0.5)
Amortization of transition obligation (asset)..... -- (2.1) (7.9) 9.2 9.2 9.2
Amortization of prior service cost................ 9.3 8.8 5.7 3.2 3.2 3.2
Recognized net actuarial loss (gain).............. -- -- (9.1) 11.2 4.9 --
Voluntary early retirement program................ -- 6.1 17.2 -- 2.3 --
- -----------------------------------------------------------------------------------------------------------
Net periodic benefit cost (income)................ $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9
===========================================================================================================
Companies' share of net benefit cost.............. $ 2.5 $ (3.2) $ (19.1) $ 14.8 $15.7 $24.7
- -----------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is
approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in
later years. Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plan. An increase in the health care
cost trend rate assumption by one percentage point would increase the total
service and interest cost components by $20.7 million and the postretirement
benefit obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
(J) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily CEI, TE, ATSI, FirstEnergy
Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The Ohio
transition plan, as discussed in the "Regulatory Plans" section, resulted in the
corporate separation of FirstEnergy's regulated and unregulated operations in
2001. Unregulated operations under FES now operate the generation
25
businesses of the Companies, CEI and TE. As a result, the Companies entered into
power supply agreements (PSA) whereby FES purchases all of the Companies'
nuclear generation and the Companies purchase their power from FES to meet their
"provider of last resort" obligations. The primary affiliated companies
transactions, including the effects of the PSA beginning in 2001, the sale and
leaseback of the Companies' transmission assets to ATSI in September 2000 and
FECO's providing support services at cost, are as follows:
2002 2001 2000
- --------------------------------------------------------------------------------
(IN MILLIONS)
OPERATING REVENUES:
PSA revenues with FES.................. $328.9 $ 355.9 $ --
Generating units rent with FES......... 178.4 178.8 --
Electric sales to CEI.................. -- -- 53.4
Electric sales to TE................... -- -- 15.9
Ground lease with ATSI................. 11.9 11.9 8.8
OPERATING EXPENSES:
Purchased power under PSA.............. 911.6 1,025.9 --
Transmission expense................... 85.3 61.0 32.4
FirstEnergy support services........... 141.4 146.8 119.0
OTHER INCOME:
Interest income from ATSI.............. 15.9 16.0 5.4
Interest income from FES............... 12.1 12.1 --
- --------------------------------------------------------------------------------
FirstEnergy does not bill directly or allocate any of its costs to
any subsidiary company. Costs are allocated to the Company from its affiliates,
GPU Service, Inc. and FirstEnergy Service Company, both subsidiaries of
FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of
the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are
directly billed or assigned at no more than cost as determined by PUHCA Rule 91.
The remaining costs are for services that are provided on behalf of more than
one company, or costs that cannot be precisely identified and are allocated
using formulas that are filed annually with the SEC on Form U-13-60. The current
allocation or assignment formulas used and their bases include multiple factor
formulas: the ratio of each company's amount of FirstEnergy's aggregate direct
payroll, number of employees, asset balances, revenues, number of customers and
other factors; and specific departmental charge ratios. Management believes that
these allocation methods are reasonable.
(K) SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value. Noncash
financing and investing activities included capital lease transactions amounting
to $1.3 million for the year 2000. There were no capital lease transactions in
2002 and 2001. Commercial paper transactions of OES Fuel, Incorporated (a wholly
owned subsidiary of the Company) that had initial maturity periods of three
months or less were reported net within financing activities under long-term
debt, prior to the expiration of the related long-term financing agreement in
March 2002, and were reflected as currently payable long-term debt on the
Consolidated Balance Sheet as of December 31, 2001.
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:
2002 2001
- ---------------------------------------------------------------------------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
(IN MILLIONS)
Long-term debt..................................... $1,776 $1,861 $2,101 $2,182
Preferred stock.................................... $ 14 $ 14 $ 135 $ 138
Investments other than cash and cash equivalents:
Debt securities:
- Maturity (5-10 years)......................... $ 570 $ 539 $ 593 $ 562
- Maturity (more than 10 years)................. 458 532 461 514
Equity securities............................... 12 12 13 13
All other....................................... 361 361 360 359
- ---------------------------------------------------------------------------------------------
$1,401 $1,444 $1,427 $1,448
=============================================================================================
26
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 Companies' ratings.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Companies have 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, government bonds and corporate bonds.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in the trust investment with a corresponding change in other
comprehensive income. Realized gains (losses) are recognized as additions
(reductions) to trust asset balances. For the year 2002, net realized gains
(losses) were approximately $(3.4) million and interest and dividend income
totaled approximately $8.9 million.
(L) REGULATORY ASSETS-
The Companies recognize, as regulatory assets, costs which the FERC,
PUCO and PPUC 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 Companies' respective transition and rate restructuring
plans. Based on those plans, the Companies continue to bill and collect
cost-based rates for their transmission and distribution services, which remain
regulated; accordingly, it is appropriate that the Companies continue the
application of SFAS 71 to those operations. The Companies recognized additional
cost recovery of $270 million in 2000 as additional regulatory asset
amortization in accordance with their prior Ohio and current Pennsylvania
regulatory plans. The Companies recognized incremental transition cost recovery
aggregating $282 million in 2002 and $274 million in 2001 in accordance with the
current Ohio transition plan and Pennsylvania restructuring plan.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2002 2001
- -----------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 1(M))
(IN MILLIONS)
Regulatory transition costs........................................... $1,840.4 $2,050.1
Customer receivables for future income taxes.......................... 127.2 139.5
Loss on reacquired debt............................................... 28.0 30.3
Employee postretirement benefit costs................................. 9.3 12.3
Other................................................................. 0.7 2.0
- -----------------------------------------------------------------------------------------------------
Total.......................................................... $2,005.6 $2,234.2
=====================================================================================================
(M) RESTATED FINANCIAL STATEMENTS
The Company has restated its financial statements for the year ended
December 31, 2002, to reflect a change in the method of amortizing the costs
associated with the Ohio transition plan. The Company amortizes transition costs
using the effective interest method. The amortization schedules originally
developed at the beginning of the transition plan in 2001 in applying this
method were based on total transition revenues, including revenues designed to
recover costs which have not yet been incurred and are not reflected as
regulatory assets in the financial statements prepared under generally accepted
accounting principles (GAAP). OE has revised the amortization schedules under
the effective interest method to consider only revenues relating to transition
regulatory assets recognized on the GAAP balance sheet. The impact of this
change will result in higher amortization of these regulatory assets in the
first several years of the transition cost recovery period compared with the
method previously applied. The change in method results in no change in total
amortization of the regulatory assets recovered through the transition period,
which is expected to end in 2006.
27
After giving effect to the restatement, total transition cost
amortization (including above market leases) is expected to approximate the
following for the years from 2003 through 2006 (in millions).
2003.............. $389
2004.............. 456
2005.............. 553
2006.............. 178
The change in amortization resulted in a decrease in net income of
$5.4 million and included an increase in net income of $15.4 million from the
cumulative impact of the adjustments related to 2001 and a $20.8 million
decrease in net income for additional amortization expense in 2002. The net
adjustment is reflected as an increase of $14.7 million in depreciation and
amortization expense and a decrease of $9.3 million in income tax expense in the
accompanying consolidated statement of income as restated.
The Company has also included in this restatement certain immaterial
adjustments that were not previously recognized in 2002. The impact of these
adjustments reduced net income reported for 2002 by $1.9 million.
The total decrease to net income of $7.3 million resulting from
these adjustments impacted the Consolidated Statement of Income previously
reported for the year ended December 31, 2002 as follows:
AS PREVIOUSLY AS
REPORTED RESTATED
-------- --------
(IN THOUSANDS)
Revenues $2,948,675 $2,948,675
Expenses 2,486,990 2,494,844
Other income 42,329 42,859
---------- ----------
Income before net interest charges 504,014 496,690
Net interest charges 140,531 140,531
---------- ----------
Net income $ 363,483 $ 356,159
Preferred stock dividend requirements 6,510 6,510
---------- ----------
Earnings on common stock $ 356,973 $ 349,649
========== ==========
The change in the amortization method and the other adjustments had
the following impact on the Consolidated Balance Sheet as of December 31, 2002:
INCREASE (DECREASE): (IN THOUSANDS)
Current assets $ (3,500)
Regulatory assets (7,200)
----------
Total assets $ (10,700)
==========
Current liabilities $ (1,032)
Deferred income taxes (8,562)
Common stockholders equity (1,106)
----------
Capitalization and liabilities $ (10,700)
==========
Net cash provided from operating activities remained unchanged at approximately
$1.1 billion in 2002.
2. LEASES
The Companies lease certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.
The Company sold portions of its ownership interest in Perry Unit 1
and Beaver Valley Unit 2 and entered into operating leases on the portions sold
for basic lease terms of approximately 29 years. During the terms of the leases,
the
28
Company continues to be responsible, to the extent of its individual combined
ownership and leasehold interests, for costs associated with the units including
construction expenditures, operation and maintenance expenses, insurance,
nuclear fuel, property taxes and decommissioning. The Company has the right, at
the end of the respective basic lease terms, to renew the leases for up to two
years. The Company also has 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. The basic rental payments are adjusted when
applicable federal tax law changes.
OES Finance, Incorporated, a wholly owned subsidiary of the Company,
maintains deposits pledged as collateral to secure reimbursement obligations
relating to certain letters of credit supporting the Company's obligations to
lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The
deposits of approximately $278 million pledged to the financial institution
providing those letters of credit are the sole property of OES Finance and are
investments which are classified as "Held to Maturity." In the event of
liquidation, OES Finance, as a separate corporate entity, would have to satisfy
its obligations to creditors before any of its assets could be made available to
the Company as sole owner of OES Finance common stock.
Consistent with the regulatory treatment, the rentals for capital
and operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 2002,
are summarized as follows:
2002 2001 2000
--------------------------------------------------------
(IN MILLIONS)
Operating leases
Interest element......... $100.9 $102.7 $107.0
Other.................... 34.6 31.6 35.1
Capital leases
Interest element......... 1.6 1.9 2.5
Other.................... 1.3 1.9 2.6
--------------------------------------------------------
Total rentals............ $138.4 $138.1 $147.2
========================================================
The future minimum lease payments as of December 31, 2002, are:
OPERATING LEASES
-----------------------------------
CAPITAL LEASE PNBV CAPITAL
LEASES PAYMENTS TRUST NET
- ----------------------------------------------------------------------------------------
(IN MILLIONS)
2003...................................... $ 2.9 $ 136.9 $ 62.9 $ 74.0
2004...................................... 4.4 137.8 58.5 79.3
2005...................................... 4.4 138.8 56.6 82.2
2006...................................... 4.4 139.9 59.6 80.3
2007...................................... 0.8 139.3 59.9 79.4
Years thereafter.......................... 3.4 1,272.6 356.4 916.2
- ----------------------------------------------------------------------------------------
Total minimum lease payments.............. 20.3 $1,965.3 $653.9 $1,311.4
======== ====== ========
Executory costs........................... 7.1
- -------------------------------------------------
Net minimum lease payments................ 13.2
Interest portion.......................... 4.9
- -------------------------------------------------
Present value of net minimum
lease payments.......................... 8.3
Less current portion...................... 1.3
- -------------------------------------------------
Noncurrent portion........................ $ 7.0
=================================================
The Company invested in the PNBV Capital Trust, which was
established to purchase a portion of the lease obligation bonds issued on behalf
of lessors in the Company's Perry Unit 1 and Beaver Valley Unit 2 sale and
leaseback transactions. The PNBV capital trust arrangement effectively reduces
lease costs related to those transactions.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
Under the Company's first mortgage indenture, the Company's
consolidated retained earnings unrestricted for payment of cash dividends on the
Company's common stock were $800.0 million at December 31, 2002.
(B) EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)-
An ESOP Trust funds most of the matching contribution for
FirstEnergy's 401(k) savings plan. All of the Companies' full-time employees
eligible for participation in the 401(k) savings plan are covered by the ESOP.
The ESOP borrowed $200 million from the Company and acquired 10,654,114 shares
of the Company's common stock
29
(subsequently converted to FirstEnergy common stock) through market purchases.
The ESOP loan is included in Other Property and Investments on the Consolidated
Balance Sheets as of December 31, 2002 and 2001 as an investment with
FirstEnergy related to the FirstEnergy savings plan. Dividends on ESOP shares
are used to service the debt. Shares are released from the ESOP on a pro rata
basis as debt service payments are made.
(C) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
-----------------------------------------------------------------------
Restricted common shares granted......... 36,922 133,162 208,400
Weighted average market price ........... $36.04 $35.68 $26.63
Weighted average vesting period (years).. 3.2 3.7 3.8
Dividends restricted..................... Yes * Yes
-----------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash on
128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
Stock option activities under the FE Programs for the past three
years were as follows:
NUMBER OF WEIGHTED AVERAGE
STOCK OPTION ACTIVITIES OPTIONS EXERCISE PRICE
-----------------------------------------------------------------------
Balance, January 1, 2000.............. 2,153,369 $25.32
(159,755 options exercisable)......... 24.87
Options granted..................... 3,011,584 23.24
Options exercised................... 90,491 26.00
Options forfeited................... 52,600 22.20
Balance, December 31, 2000........... 5,021,862 24.09
(473,314 options exercisable)......... 24.11
Options granted..................... 4,240,273 28.11
Options exercised................... 694,403 24.24
Options forfeited................... 120,044 28.07
Balance, December 31, 2001............ 8,447,688 26.04
(1,828,341 options exercisable)....... 24.83
Options granted..................... 3,399,579 34.48
Options exercised................... 1,018,852 23.56
Options forfeited................... 392,929 28.19
Balance, December 31, 2002........... 10,435,486 28.95
(1,400,206 options exercisable)....... 26.07
30
As of December 31, 2002, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected
in net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1G - "Stock-Based Compensation."
(D) PREFERRED AND PREFERENCE STOCK-
Penn's 7.75% series of preferred stock has a restriction which
prevents early redemption prior to July 2003. All other preferred stock may be
redeemed by the Companies in whole, or in part, with 30-60 days' notice.
The Company has eight million authorized and unissued shares of
preference stock having no par value.
(E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Penn's 7.625% series has an annual sinking fund requirement for
7,500 shares.
The Companies' preferred shares are retired at $100 per share plus accrued
dividends. Annual sinking fund requirements are approximately $750,000 in each
year 2003 through 2006 and $11.25 million in 2007.
(F) LONG-TERM DEBT-
Each of the Companies has a first mortgage indenture under which it
issues from time to time first mortgage bonds secured by a direct first mortgage
lien on substantially all of its property and franchises, other than
specifically excepted property. The Companies have various debt covenants under
their respective financing arrangements. The most restrictive of their debt
covenants relate to the nonpayment of interest and/or principal on debt which
could trigger a default and the maintenance of minimum fixed charge ratios and
debt to capitalization ratios. There also exists cross-default provisions among
financing arrangements of FirstEnergy and the Companies.
Based on the amount of bonds authenticated by the respective
mortgage bond trustees through December 31, 2002, the Companies' annual sinking
and improvement fund requirements for all bonds issued under the various
mortgage indentures of the Companies amounts to $39 million. The Companies
expect to deposit funds with their respective mortgage bond trustees in 2003
that will then be withdrawn upon the surrender for cancellation of a like
principal amount of bonds, specifically authenticated for such purposes against
unfunded property additions or against previously retired bonds. This method can
result in minor increases in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(IN MILLIONS)
----------------------------------------------------
2003................................. $561.2
2004................................. 258.3
2005................................. 136.8
2006................................. 5.6
2007................................. 5.8
----------------------------------------------------
Included in the table above are amounts for various variable
interest rate long-term debt which have provisions by which individual debt
holders have the option to "put back" or require the respective debt issuer to
redeem their debt at those times when the interest rate may change prior to its
maturity date. These amounts are $311 million and $161 million in 2003 and 2004,
respectively, which represents the next date at which the debt holders may
exercise this provision.
The Companies' obligations to repay certain pollution control
revenue bonds are secured by several series of first mortgage bonds. Certain
pollution control revenue bonds are entitled to the benefit of irrevocable bank
letters of credit of $171.5 million and noncancelable municipal bond insurance
policies of $238.9 million to pay principal of, or interest on, the pollution
control revenue bonds. To the extent that drawings are made under the letters of
credit or policies, the Companies are entitled to a credit against their
obligation to repay those bonds. The Companies pay annual fees of 1.375% of the
amounts of the letters of credit to the issuing banks and are obligated to
reimburse the banks for any drawings thereunder.
31
(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, 2002, accumulated other comprehensive loss consisted of a minimum liability
for unfunded retirement benefits of $(64.6) million and unrealized gains on
investments in securities available for sale of $5.1 million.
4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding as of December 31, 2002, consisted
of $22.6 million of bank borrowings and $159.7 million of OES Capital,
Incorporated commercial paper. OES Capital is a wholly owned subsidiary of the
Company whose borrowings are secured by customer accounts receivable. OES
Capital can borrow up to $170 million under a receivables financing agreement at
rates based on certain bank commercial paper and is required to pay an annual
fee of 0.20% on the amount of the entire finance limit. The receivables
financing agreement expires in August 2003. As of December 31, 2002, the Company
also had total short-term borrowings of $225.3 million from its affiliates. The
weighted average interest rates on short-term borrowings outstanding as of
December 31, 2002 and 2001, were 1.63% and 2.45%, respectively.
The Company has lines of credit with domestic banks that provide for
borrowings of up to $34 million under various interest rate options. Short-term
borrowings may be made under these lines of credit on its unsecured notes. To
assure the availability of these lines, the Company is required to pay annual
commitment fees of 0.20%. These lines expire at various times during 2003.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Companies' current forecast reflects expenditures of
approximately $391 million for property additions and improvements from
2003-2007, of which approximately $139 million is applicable to 2003.
Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $97 million, of which approximately $42 million
applies to 2003. During the same periods, the Companies' nuclear fuel
investments are expected to be reduced by approximately $85 million and $41
million, respectively, as the nuclear fuel is consumed.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on their ownership and leasehold interests in the Beaver Valley Station
and the Perry Plant, the Companies' 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 $168.1 million per incident but not more than $19.1
million in any one year for each incident.
The Companies are also insured as to their respective interests in
Beaver Valley 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 Companies have also obtained
approximately $537 million of insurance coverage for replacement power costs for
their respective interests in Beaver Valley and Perry. Under these policies, the
Companies can be assessed a maximum of approximately $31.6 million for incidents
at any covered nuclear facility occurring during a policy year which are in
excess of accumulated funds available to the insurer for paying losses.
The Companies intend 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
Companies' 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 Companies' insurance policies, or to the extent such insurance
becomes unavailable in the future, the Companies would remain at risk for such
costs.
(C) ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. In
accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note
1, generation operations and any related additional capital expenditures for
environmental compliance are the responsibility of FirstEnergy's competitive
services business unit.
32
The Companies are 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 Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies believe they are in compliance with the current SO2
and nitrogen oxides (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOx reductions are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional NOx
reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx
Transport Rule imposes uniform reductions of NOx emissions (an approximate 85%
reduction in utility plant NOx emissions from projected 2007 emissions) across a
region of nineteen states and the District of Columbia, including Ohio and
Pennsylvania, based on a conclusion that such NOx emissions are contributing
significantly to ozone pollution in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets established by the EPA. Pennsylvania submitted a SIP that requires
compliance with the NOx budgets at the Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient
Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals found constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating
ultra-fine particulates but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these regulations may be substantial and will depend if and how they are
ultimately implemented by the states in which the Companies operate affected
facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against the Companies in the U.S. District Court for the Southern District of
Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act based on operation and maintenance of the Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. Although unable to predict the
outcome of these proceedings, the Companies believe the Sammis Plant is in full
compliance with the Clean Air Act and the NOV and complaint are without merit.
Penalties could be imposed if the Sammis Plant continues to operate without
correcting the alleged violations and a court determines that the allegations
are valid. The Sammis Plant continues to operate while these proceedings are
pending (see Note 9).
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on the Companies'
earnings and competitive position. These environmental regulations affect the
Companies' earnings and competitive position to the extent they compete with
companies that are not subject to such regulations and therefore do not bear the
risk of costs associated with compliance, or failure to comply, with such
regulations. The Companies believe they are in material compliance with existing
regulations but are unable to predict whether environmental regulations will
change and what, if any, the effects of such change would be.
(D) LEGAL MATTERS-
Various lawsuits, claims and proceedings related to the Companies'
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant applicable to the Companies are described above.
33
6. RECENTLY ISSUED ACCOUNTING STANDARDS:
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions beginning in the first
interim or annual reporting period beginning after June 15, 2003 (our third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
The Company currently has transactions with an entity in connection
with a sale and leaseback arrangement which fall within the scope of this
interpretation and which is reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. The Company currently consolidates the majority
of these entities and believes it will continue to consolidate following the
adoption of FIN 46. In addition to the entities the Company is currently
consolidating the Company believes that the PNBV Capital Trust, which was used
to acquire a portion of the off-balance sheet debt issued in connection with the
sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley
Unit 2, would require consolidation. Ownership of the trust includes a
three-percent equity interest by a nonaffiliated party and a three-percent
equity interest by OES Ventures, a wholly owned subsidiary of the Company. Full
consolidation of the trust under FIN 46 would change the characterization of the
PNBV trust investment to a lease obligation bond investment. Also, consolidation
of the outside minority interest would be required, which would increase assets
and liabilities by $11.6 million.
7. OTHER INFORMATION:
The following financial data provides supplemental unaudited
information to the consolidated financial statements previously reported in 2001
and 2000:
(A) CONSOLIDATED STATEMENTS OF CASH FLOWS
2002 2001 2000
---- ---- ----
(IN THOUSANDS)
Other Cash Flows From Operating Activities:
Accrued taxes................................. $208,945 $ 26,606 $ 24,863
Accrued interest.............................. (4,844) (1,053) (3,466)
Prepayments and other......................... 38,737 26,393 (3,252)
All other..................................... (29,909) (76,858) (9,392)
- -----------------------------------------------------------------------------------
Total-Other................................. $212,929 $ (24,912) $ 8,753
===================================================================================
Other Cash Flows from Investing Activities:
Retirements and transfers..................... $ 7,476 $ 15,528 $ (6,854)
Nuclear decommissioning trust investments..... (15,688) (15,816) (8,879)
Other investments............................. 18,820 3,209 --
All other..................................... 23,524 (33) 7,350
- -----------------------------------------------------------------------------------
Total-Other................................. $ 34,132 $ 2,888 $ (8,383)
===================================================================================
(B) CONSOLIDATED STATEMENTS OF TAXES
2002 2001 2000
---- ---- ----
(IN THOUSANDS)
Other Accumulated Deferred Income
Taxes at December 31:
Retirement Benefits....................... $ 20,969 $ 24,591 $ 30,896
All other................................. 63,344 40,295 (199)
- --------------------------------------------------------------------------------
Total-Other............................. $ 84,313 $ 64,886 $ 30,697
================================================================================
34
8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002 (A) JUNE 30, 2002 (A) SEPTEMBER 30, 2002 (A) DECEMBER 31, 2002 (A)
- ---------------------------------------------------------------------------------------------------------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
(IN MILLIONS)
Operating Revenues $707.8 $707.8 $744.5 $744.5 $813.3 $813.3 $683.1 $683.1
Operating Expenses and Taxes 610.7 600.4 605.9 611.1 658.8 664.5 611.6 618.8
Operating Income 97.1 107.4 138.6 133.4 154.5 148.8 71.5 64.2
- ---------------------------------------------------------------------------------------------------------------------------------
Other Income 0.5 0.5 15.1 15.1 14.2 14.2 12.5 13.0
Net Interest Charges 41.2 41.2 35.9 35.9 33.7 33.7 29.7 29.8
Net Income $ 56.4 66.7 $117.8 112.6 135.0 129.3 54.3 47.5
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings on Common Stock $ 53.8 $ 64.0 $115.2 $110.1 $134.4 $128.6 $ 53.6 $ 46.9
=================================================================================================================================
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
THREE MONTHS ENDED 2001 2001 2001 2001
- ------------------------------------------------------------------------------------------------
(IN MILLIONS)
Operating Revenues................. $783.1 $744.7 $815.7 $712.9
Operating Expenses and Taxes....... 694.3 606.8 693.2 595.3
- ------------------------------------------------------------------------------------------------
Operating Income................... 88.8 137.9 122.5 117.6
Other Income....................... 12.4 17.8 18.7 19.8
Net Interest Charges............... 47.0 50.5 45.0 42.8
- ------------------------------------------------------------------------------------------------
Net Income......................... $ 54.2 $105.2 $ 96.2 $ 94.6
================================================================================================
Earnings on Common Stock........... $ 51.5 $102.5 $ 93.5 $ 92.0
================================================================================================
(a) See Note 1(M) for discussion of restated financial data.
9. SUBSEQUENT EVENTS
ENVIRONMENTAL MATTERS-
On August 8, 2003, FirstEnergy, OE and Penn reported a development
regarding a complaint filed by the U.S. Department of Justice with respect to
the W.H. Sammis Plant (see Note 5(C) Commitments and Contingencies -
Environmental Matters). As reported, on August 7, 2003, the United States
District Court for the Southern District of Ohio ruled that 11 projects
undertaken at the Sammis Plant between 1984 and 1998 required pre-construction
permits under the Clean Air Act. The ruling concludes the liability phase of the
case, which deals with applicability of Prevention of Significant Deterioration
provisions of the Clean Air Act. The remedy phase, which is currently scheduled
to be ready for trial beginning March 15, 2004, will address civil penalties and
what, if any, actions should be taken to further reduce emissions at the plant.
In the ruling, the Court indicated that the remedies it "may consider and impose
involved a much broader, equitable analysis, requiring the Court to consider air
quality, public health, economic impact, and employment consequences. The Court
may also consider the less than consistent efforts of the EPA to apply and
further enforce the Clean Air Act." Management is unable to predict the ultimate
outcome of this matter. The potential penalties that may be imposed, as well as
the capital expenditures necessary to comply with substantive remedial measures
that may be required, may have a material adverse impact on the Company's
financial condition. Management is unable to predict the ultimate outcome of
this matter. The potential penalties that may be imposed, as well as the capital
expenditures necessary to comply with substantive remedial measures that may be
required, may have a material adverse impact on the Company's financial
condition.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED-
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 is effective for financial
instruments entered into or modified after May 31, 2003 and is effective at the
beginning of the first interim period beginning after June 15, 2003 (OE's third
quarter of 2003) for all other financial instruments.
OE did not enter into or modify any financial instruments within the
scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1,
2003, OE expects to classify as debt the preferred stock of consolidated
subsidiaries subject to mandatory redemptions with a carrying value of
approximately $13.5 million as of June 30, 2003. Subsidiary preferred dividends
on OE's Consolidated Statements of Income are currently included in net interest
35
charges. Therefore, the application of SFAS 150 will not require the
reclassification of such preferred dividends to net interest charges.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003 which would correspond to OE's
fourth quarter of 2003. The issue supersedes earlier DIG Issue C11,
"Interpretation of Clearly and Closely Related in Contracts That Qualify for the
Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance
regarding when the presence in a contract of a general index, such as the
Consumer Price Index, would prevent that contract from qualifying for the normal
purchases and normal sales (NPNS) exception under SFAS 133, as amended, and
therefore exempt from the mark-to-market treatment of certain contracts. DIG
Issue C20 is to be applied prospectively to all existing contracts as of its
effective date and for all future transactions. If it is determined under DIG
Issue C20 guidance that the NPNS exception was claimed for an existing contract
that was not eligible for this exception, the contract will be recorded at fair
value, with a corresponding adjustment of net income as the cumulative effect of
a change in accounting principle in the fourth quarter of 2003. OE is currently
assessing the new guidance and has not yet determined the impact on its
financial statements.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when
arrangements contain a lease. Based on the EITF consensus, an arrangement
contains a lease if (1) it identifies specific property, plant or equipment
(explicitly or implicitly), and (2) the arrangement transfers the right to the
purchaser to control the use of the property, plant or equipment. The consensus
will be applied prospectively to arrangements committed to, modified or acquired
through a business combination, beginning in the third quarter of 2003. OE is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
36
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of Ohio Edison Company:
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of Ohio Edison Company
(a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December
31, 2002, and the results of their operations and their cash flows for the year
then ended in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on these
financial statements based on our audit. We conducted our audit of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion. The consolidated financial
statements of Ohio Edison Company and subsidiaries as of December 31, 2001 and
for each of the two years in the period ended December 31, 2001 were audited by
other independent auditors who have ceased operations. Those independent
auditors expressed an unqualified opinion on those financials statements in
their report dated March 18, 2002.
As discussed in Note 1(M) to the consolidated financial statements, the Company
has restated its previously issued consolidated financial statements for the
year ended December 31, 2002.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003, except as to Note 1(M), which is as of August 18, 2003
37
The following report is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). This report has not been reissued by Andersen and Andersen did
not consent to the incorporation by reference of this report (as included in
this Form 10-K/A) into any of the Company's registration statements.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF OHIO EDISON COMPANY:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Ohio Edison Company (an Ohio corporation and
wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December
31, 2001 and 2000, and the related consolidated statements of income, common
stockholder's equity, preferred stock, cash flows and taxes for each of the
three years in the period ended December 31, 2001. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Ohio Edison Company and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.
38