OHIO EDISON COMPANY
2000 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. 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 2-7
Consolidated Statements of Income 8
Consolidated Balance Sheets 9
Consolidated Statements of Capitalization 10-11
Consolidated Statements of Common Stockholder's Equity 12
Consolidated Statements of Preferred Stock 12
Consolidated Statements of Cash Flows 13
Consolidated Statements of Taxes 14
Notes to Consolidated Financial Statements 15-25
Report of Independent Public Accountants 26
OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
2000 1999 1998 1997 1996
- ---------------------------------------------------------------------------------------------------
(In thousands)
Operating Revenues $2,726,708 $2,686,949 $2,519,662 $2,473,582 $2,469,785
--------------------------------------------------------------
Operating Income $ 482,321 $ 473,042 $ 486,920 $ 488,568 $ 530,069
--------------------------------------------------------------
Income Before Extraordinary Item $ 336,456 $ 297,689 $ 301,320 $ 293,194 $ 315,170
--------------------------------------------------------------
Net Income $ 336,456 $ 297,689 $ 270,798 $ 293,194 $ 315,170
--------------------------------------------------------------
Earnings on Common Stock $ 325,332 $ 286,142 $ 258,828 $ 280,802 $ 302,673
--------------------------------------------------------------
Total Assets $8,154,151 $8,700,746 $8,923,826 $9,158,141 $9,218,623
--------------------------------------------------------------
Capitalization at December 31:
Common Stockholder's Equity $2,556,992 $2,624,460 $2,681,873 $2,724,319 $2,503,359
Preferred Stock:
Not Subject to Mandatory
Redemption 200,070 200,070 211,870 211,870 211,870
Subject to Mandatory Redemption 135,000 140,000 145,000 150,000 155,000
Long-Term Debt 2,000,622 2,175,812 2,215,042 2,569,802 2,712,760
--------------------------------------------------------------
Total Capitalization $4,892,684 $5,140,342 $5,253,785 $5,655,991 $5,582,989
--------------------------------------------------------------
Capitalization Ratios:
Common Stockholder's Equity 52.3% 51.1% 51.0% 48.2% 44.8%
Preferred Stock:
Not Subject to Mandatory
Redemption 4.1 3.9 4.0 3.7 3.8
Subject to Mandatory Redemption 2.7 2.7 2.8 2.7 2.8
Long-Term Debt 40.9 42.3 42.2 45.4 48.6
--------------------------------------------------------------
Total Capitalization 100.0% 100.0% 100.0% 100.0% 100.0%
--------------------------------------------------------------
Kilowatt-Hour Sales (Millions):
Residential 9,362 9,483 8,773 8,631 8,704
Commercial 8,031 8,238 7,590 7,335 7,246
Industrial 11,484 11,310 10,803 11,202 11,089
Other 149 151 150 150 147
--------------------------------------------------------------
Total Retail 29,026 29,182 27,316 27,318 27,186
Total Wholesale 9,860 6,881 5,706 5,241 7,076
--------------------------------------------------------------
Total 38,886 36,063 33,022 32,559 34,262
--------------------------------------------------------------
Customers Served:
Residential 1,014,379 1,016,793 1,004,552 995,605 988,179
Commercial 116,931 115,581 113,820 111,189 113,795
Industrial 4,569 4,627 4,598 4,568 4,590
Other 1,606 1,539 1,476 1,415 1,331
--------------------------------------------------------------
Total 1,137,485 1,138,540 1,124,446 1,112,777 1,107,895
--------------------------------------------------------------
Number of Employees (a) 1,647 2,734 2,832 4,215 4,273
<FN>
(a) Reduction in 2000 reflects transfer of responsibility for generation
operations to FirstEnergy Corp.'s competitive services unit.
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 that is subject to certain
risks and uncertainties. Such statements typically contain, but are not
limited to, the terms anticipate, potential, expect, believe, estimate and
similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and
margins, changes in markets for energy services, changing energy and
commodity market prices, legislative and regulatory changes (including
revised environmental requirements), and the availability and cost of
capital.
Results of Operations
- ---------------------
Earnings on common stock for 2000 increased 14% to $325.3
million from $286.1 million in 1999. Results for 2000 were favorably
affected by higher operating revenues, lower fuel expenses, and reductions
in general taxes and net interest charges, which were partially offset by
higher nuclear and other operating costs. In 1999, earnings on common
stock increased 11% to $286.1 million from $258.8 million in 1998
primarily due to higher operating revenues, the absence of an
extraordinary charge and unusually high purchased power costs experienced
in 1998 and lower interest costs that were principally offset by an
increase in depreciation and amortization.
Operating revenues increased by $39.8 million in 2000 following
a $167.3 million increase in 1999. The sources of increases in operating
revenues during 2000 and 1999 are summarized in the following table:
Sources of Revenue Changes 2000 1999
- --------------------------------------------------------
Increase (Decrease) (In millions)
Change in retail kilowatt-hour sales $(12.6) $151.3
Decrease in average retail price (2.9) (36.3)
Increase in wholesale sales 33.2 54.6
Increase in transmission-related
services 18.9 0.4
All other changes 3.2 (2.7)
- ---------------------------------------------------------
Net Increase in Operating Revenues $ 39.8 $167.3
=========================================================
Electric Sales
Additional kilowatt-hour sales to the wholesale market were the
largest source of the increase in operating revenues in 2000, compared to
the prior year, primarily due to additional available generating capacity.
Transmission-related revenues also contributed to the increase in
operating revenues in 2000. These increases were partially offset by lower
retail kilowatt-hour sales and a reduction in the average retail unit
price resulting from the transition rate credit program and a changing
sales mix. Retail kilowatt-hour sales to industrial customers increased
while kilowatt-hour sales to both residential and commercial customers
decreased in 2000 from the previous year. The overall reduction in retail
kilowatt-hour sales reflected a softening in the service area economy and
cooler summer weather during 2000, compared to the above-normal
temperatures experienced in 1999.
Sales growth in both the retail and wholesale markets produced
the increase in operating revenues in 1999, compared to 1998. Strong
consumer-driven economic growth and, to a lesser extent, the weather,
contributed to the increased retail sales. Weather-induced electricity
demand in the wholesale market and additional available generation
combined to increase sales to wholesale customers. Changes in kilowatt-
hour sales by customer class in 2000 and 1999 are summarized in the
following table:
Changes in KWH Sales 2000 1999
- --------------------------------------------------
Increase (Decrease)
Residential (1.3)% 8.1%
Commercial (2.5)% 8.6%
Industrial 1.6% 4.7%
- --------------------------------------------------
Total Retail (0.5)% 6.8%
Wholesale 43.3% 20.6%
- --------------------------------------------------
Total Sales 7.8% 9.2%
- --------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes increased $30.5 million in
2000 and $181.2 million in 1999. The increase in 2000 resulted primarily
from higher operation and maintenance costs. While operation and
maintenance costs were also up in 1999, the increase in operating expenses
and taxes in that year was principally due to additional depreciation and
amortization. The increases in operation and maintenance costs in both
2000 and 1999 occurred despite a reduction in fuel and purchased power
costs. Fuel expenses were $56.0 million lower in 2000, compared to 1999,
which accounted for nearly all of the reduction in fuel and purchased
power costs. Several factors contributed to the lower fuel expense, which
occurred despite an 11.1% increase in output from our generating units.
Factors contributing to lower fuel expense included:
o A higher proportion of nuclear generation (which has lower unit fuel
costs than fossil fuel) due to improved nuclear availability and
increased nuclear ownership from the exchange of generating assets
with Duquesne Light Company (Duquesne) in December 1999;
o The expiration of an above-market coal contract at the end of 1999;
and
o Continued improvement of coal-blending strategies, which resulted in
the use of additional lower-cost fuel and enhanced the efficiency
and cost-competitiveness of our fossil generation.
In 1999, the entire $35.8 million reduction in fuel and
purchased power costs was due to lower purchased power costs. Much of the
decrease occurred in the second quarter of 1999 due to the absence of
unusual conditions experienced in the summer of 1998. Those costs were
incurred during a period of record heat and humidity in late June 1998,
which coincided with a regional power shortage resulting in high prices
for purchased power. Unscheduled outages at Beaver Valley Units 1 and 2 at
the same time required us to purchase significant amounts of power on the
spot market. Although above normal temperatures were also experienced in
1999, we maintained a stronger capacity position compared to the previous
year and better met customer demand from our own generation sources.
Nuclear operating costs increased by $54.1 million in 2000 and
$32.4 million in 1999 due to refueling outage costs and increased
ownership of the Beaver Valley Plant following the Duquesne asset swap in
early December 1999. Increased Beaver Valley Plant ownership (including
nonrecurring swap-related liabilities assumed) also contributed to higher
nuclear operating costs in 1999 compared to the preceding year, along with
outage-related costs at Beaver Valley Unit 2 and the Perry Plant.
Other operating costs rose $23.8 million in 2000, compared to
1999, with most of the increase resulting from higher transmission costs
in the fourth quarter as American Transmission Systems, Inc. (ATSI), an
affiliated company, assumed responsibility for transmission operations and
charged us for transmission services (see Financial Condition, Capital
Resources and Liquidity). The impact of the higher transmission costs was
offset in part by income received from ATSI under a ground lease
arrangement and interest income from the promissory note received in
connection with the sale of the transmission facilities. Also contributing
to the increase in other operating costs in 2000 were higher reserves
established for potentially uncollectible accounts of customers in the
steel sector who are experiencing significant financial pressures from
foreign steel competition, and the cost of additional leased portable
diesel generators, acquired as part of our summer supply strategy.
Partially offsetting those higher operating costs were $11.9 million in
increased gains realized from the sale of emission allowances. In 1999,
higher customer and sales expenses, including expenditures for energy
marketing programs, information system requirements and other customer-
related costs, as well as higher distribution costs from storm repairs and
overhead line maintenance all contributed to higher other operating costs,
compared to the preceding year.
Total accelerated cost recovery under the Company's rate
reduction plan and Penn's restructuring plan increased by $23.2 million in
2000 and $160.6 million in 1999, compared to the prior year. The table
below summarizes the accelerated cost recovery by income statement
caption:
Regulatory Plan Accelerations 2000 1999 1998
- ---------------------------------------------------------------
(In millions)
Depreciation and amortization $332.6 $333.3 $172.9
Income tax amortization & other 42.6 18.7 18.5
- ---------------------------------------------------------------
Total Plan Accelerations $375.2 $352.0 $191.4
===============================================================
The impact of accelerated cost recovery on depreciation and amortization
was relatively unchanged in 2000 from the preceding year, but accounted
for most of the increase in depreciation and amortization in 1999,
compared to 1998. General taxes decreased $14.4 million in 2000 from 1999
primarily due to a prior year gross receipts tax refund, favorable
property tax law changes and the phase-out of Pennsylvania's Capital Stock
and Franchise Tax.
Other Income
Other income increased $10.1 million in 2000, compared to the
previous year, principally due to the interest earned on long-term notes
from ATSI (see Financial Condition, Capital Resources and Liquidity) and
short-term loans to other affiliated companies.
Net Interest Charges
Net interest charges decreased by $19.4 million in 2000 and
$12.0 million in 1999, compared to the prior year. We continue to redeem
and refinance our outstanding debt and preferred stock, thus maintaining
the downward trend in our financing costs during 2000. Net redemptions of
long-term debt and preferred stock totaled $121.4 million and refinancings
totaled $186.5 million in 2000.
Effects of SFAS 71 Discontinuation
- ----------------------------------
The application of Statement of Financial Accounting Standards
No. (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation"
was discontinued for the Company's generation business effective with
approval by the Public Utilities Commission of Ohio (PUCO) of the Ohio
transition plan. Beginning June 30, 2000, the Company's balance sheet
reflected that discontinuance with $1.2 billion of impaired generating
plant investments recognized as regulatory assets which will be recovered
as transition costs. We expect the incremental amortization of transition
costs in 2001 to be lower than the depreciation and amortization
accelerated under our former regulatory plan in 2000.
On June 18, 1998, the Pennsylvania Public Utility Commission
authorized Penn's rate restructuring plan that resulted in the
discontinuation of SFAS 71 to Penn's generation business. Under the plan,
Penn's rates were restructured to establish separate charges for
transmission and distribution services; generation (which is subject to
competition); and stranded cost recovery. A total of $215.4 million of
impaired nuclear generating plant investments were recognized as
regulatory assets to be recovered through the stranded cost recovery
charge. The portion of generating plant investment not recovered through
future customer rates resulted in a $30.5 million extraordinary after-tax
write-down in 1998.
We continue to bill and collect cost-based rates for
transmission and distribution services, which remain subject to cost-based
regulation; accordingly, it is appropriate that we continue the
application of SFAS 71 to those operations.
Financial Condition, Capital Resources and Liquidity
- ----------------------------------------------------
On September 1, 2000, FirstEnergy Corp.'s (FirstEnergy) electric
utility operating companies transferred $1.2 billion of their transmission
assets to ATSI. As part of the transfer, we sold to ATSI $727.1 million of
our transmission assets, net of $339.4 million of accumulated depreciation
and $10.9 million of investment tax credits for $169.6 million of cash and
$207.2 million of long-term notes.
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
5.78 in 1995 to 7.45 in 2000, which enhances our financial flexibility.
Over the same period, our charter ratio, a measure of our ability to issue
preferred stock, improved from 2.31 to 2.88 and our common stockholder's
equity as a percentage of capitalization rose from approximately 43% at
the end of 1995 to 52% at the end of 2000. Over the last five years, we
have reduced the average cost of long-term debt from 8.00% in 1995 to
7.58% at the end of 2000. Net redemptions of long-term debt and preferred
stock and long-term debt refinancings completed in 2000 are expected to
generate annual savings of about $8 million.
We had about $18.3 million of cash and temporary investments and
$315.4 million of short-term indebtedness as of December 31, 2000. Our
unused borrowing capability included $187.5 million under revolving lines
of credit and a $2.0 million bank facility that provides for borrowings on
a short-term basis at the bank's discretion. At the end of 2000, we had
the capability to issue $1.3 billion of additional first mortgage bonds on
the basis of property additions and retired bonds. Based upon the earnings
coverage test under our charter, we could issue $1.8 billion of preferred
stock (assuming no additional debt was issued).
Our cash requirements in 2001 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without issuing new securities. During
2000, we reduced our total debt by approximately $330 million. We have
cash requirements of approximately $1.0 billion for the 2001-2005 period
to meet scheduled maturities of long-term debt and preferred stock. Of
that amount, approximately $23.2 million relates to 2001.
Our capital spending for the period 2001-2005 is expected to be
about $513 million (excluding nuclear fuel) of which approximately $118
million applies to 2001. Investments for additional nuclear fuel during
the 2001-2005 period are estimated to be approximately $187 million, of
which about $39 million relates to 2001. During the same periods, our
nuclear fuel investments are expected to be reduced by approximately $217
million and $45 million, respectively, as the nuclear fuel is consumed.
Also, we have operating lease commitments, net of PNBV Capital Trust cash
receipts, of approximately $373 million for the 2001-2005 period, of which
approximately $68 million relates to 2001.
Moody's Investors Service upgraded our credit ratings on
September 27, 2000 and Fitch upgraded our credit ratings on October 30,
2000. The improved credit ratings should lower the cost of future
borrowings. Our credit ratings remain under review for further possible
upgrades by Moody's. The following table summarizes the changes in credit
ratings:
Credit Ratings Before Upgrade After Upgrade
- -------------------------------------------------------------------
Moody's Moody's
Investors Investors
Service Fitch Service Fitch
- --------------------------------------------------------------------
OE
- --
First mortgage bonds Baa2 BBB Baa1 BBB+
Preferred Stock ba1 BB+ baa2 BBB-
Penn
- ----
First mortgage bonds Baa2 BBB+ Baa1 Unchanged
Preferred Stock ba1 BBB baa2 Unchanged
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced
since a significant portion of our debt has fixed interest rates, as noted
in the table below. We are subject to the inherent interest rate 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 are
recognized by making corresponding changes to the decommissioning
liability, as described in Note 1.
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
2001 2002 2003 2004 2005 after Total Value
- ------------------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than Cash
and Cash Equivalents:
Fixed Income $ 24 $ 27 $ 31 $306 $ 29 $712 $1,129 $1,158
Average interest rate 7.6% 7.8% 7.9% 7.8% 7.9% 7.7% 7.7%
- -------------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $ 18 $324 $248 $ 96 $135 $690 $1,511 $1,563
Average interest rate 8.0% 7.8% 8.2% 7.3% 7.2% 7.1% 7.5%
Variable rate $100 $594 $ 694 $ 694
Average interest rate 7.4% 4.8% 5.2%
Short-term Borrowings $315 $ 315 $ 315
Average interest rate 6.9% 6.9%
- -------------------------------------------------------------------------------------------------------
Preferred Stock $ 5 $ 1 $ 1 $ 1 $ 1 $131 $ 140 $ 138
Average dividend rate 8.5% 7.6% 7.6% 7.6% 7.6% 8.9% 8.8%
- -------------------------------------------------------------------------------------------------------
Outlook
- -------
On July 19, 2000, the PUCO approved FirstEnergy's plan for
transition to customer choice in Ohio (see Note 1), filed on our behalf,
as well as for our affiliated Ohio electric utility operating companies --
CEI and TE. As part of its authorization, the PUCO approved a settlement
agreement between FirstEnergy and major groups representing most of
FirstEnergy's Ohio customers regarding the transition to customer choice
in selection of alternative suppliers. On January 1, 2001, electric choice
became available to FirstEnergy's Ohio customers. Under the plan, we
continue to deliver power to homes and businesses through our existing
distribution system, which remains regulated. However, our rates have been
restructured to establish separate charges for transmission and
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 market prices plus an incentive, and the customer
receives a generation charge from the alternative supplier. The transition
cost portion of rates provides for recovery of certain amounts not
otherwise recoverable in a competitive generation market (such as
regulatory assets). The transition costs will be paid by all customers
regardless of whether or not they choose an alternative supplier. Under
the plan, we assume the risk of not recovering up to $250 million of
transition revenue if the rate of customers (excluding contracts and full-
service accounts), switching their service from us has not reached an
average of 20% over any consecutive twelve-month period by December 31,
2005 -- the end of the market development period. We also committed under
the transition agreement to make available 560 MW of our generating
capacity to marketers, brokers and aggregators at set prices, to be used
for sales only to retail customers in our Ohio service area. Through
February 8, 2001, approximately 409 MW of the 560 MW supply commitment had
been secured by alternative suppliers. We began accepting customer
applications for switching to alternative suppliers on December 8, 2000;
as of February 8, 2001, we had been notified that about 55,000 of our
customers requested generation services from other authorized suppliers,
including FirstEnergy Services Corp. (FE Services), an affiliated company.
Beginning in 2001, Ohio utilities which offer both competitive
and regulated retail electric services must implement a corporate
separation plan approved by the PUCO -- one which provides a clear
separation between regulated and competitive operations. Since
FirstEnergy's regionally-focused retail sales strategy envisions the
continued operation of both regulated and competitive operations, its
transition plan included details for corporate separation. The approved
plan is consistent with the way FirstEnergy managed its businesses in
2000, through a competitive services unit, a utility services unit and a
corporate support services unit. FE Services provides competitive retail
energy services while we continue to provide regulated distribution
services. FirstEnergy Generation Corp. (FE Generation), an associated
company, leases fossil plants from us and operates those plants. We expect
that the transfer of our fossil generating assets to FE Generation will be
completed by the end of the market development period. All of our power
supply requirements are provided by FE Services to satisfy our "provider
of last resort" obligation under the FirstEnergy transition plan, as well
as grandfathered wholesale contracts.
We are in compliance with current sulfur dioxide and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of
1990. In 1998, the EPA finalized regulations requiring additional NOx
reductions in the future from our Ohio and Pennsylvania facilities (see
Note 5). We continue to evaluate our compliance plans and other compliance
options.
In July 1997, the EPA changed 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 on the manner in which they are ultimately implemented, if
at all, by the states in which we operate affected facilities.
In 1999, we received notification of pending legal actions based
on alleged violations of the Clean Air Act at our W. H. Sammis Plant
involving the states of New York and Connecticut as well as the U.S.
Department of Justice. The civil complaint filed by the U.S. Department of
Justice requests installation of "best available control technology" as
well as civil penalties of up to $27,500 per day of violation. We believe
the Sammis Plant is in full compliance with the Clean Air Act and the
legal actions are without merit. However, we are unable to predict the
outcome of this litigation. 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 the matter is being decided.
Under federal environmental law and related federal and state
waste regulations, certain fossil-fuel combustion waste products, such as
coal ash, were exempted from hazardous waste disposal requirements pending
the EPA's evaluation of the need for future regulation. The EPA has issued
its final regulatory determination that regulation of coal ash as a
hazardous waste is unnecessary. On April 25, 2000, the EPA announced that
it will develop national standards regulating disposal of coal ash as a
nonhazardous waste.
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.
On August 8, 2000, our parent company, FirstEnergy Corp.,
entered into an agreement to merge with GPU, Inc, a Pennsylvania
corporation, headquartered in Morristown, New Jersey. The target date for
completing the merger is by the end of the second quarter of 2001. We will
continue to be a wholly owned subsidiary of FirstEnergy Corp.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2000 1999 1998
- ----------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES $2,726,708 $2,686,949 $2,519,662
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power 418,790 475,792 511,645
Nuclear operating costs 366,387 312,289 279,917
Other operating costs 456,246 432,476 411,985
---------- ---------- ----------
Total operation and maintenance expenses 1,241,423 1,220,557 1,203,547
Provision for depreciation and amortization 578,679 582,197 411,979
General taxes 225,849 240,281 242,524
Income taxes 198,436 170,872 174,692
---------- ---------- ----------
Total operating expenses and taxes 2,244,387 2,213,907 2,032,742
---------- ---------- ----------
OPERATING INCOME 482,321 473,042 486,920
OTHER INCOME 55,976 45,846 47,621
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES 538,297 518,888 534,541
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt 165,409 178,217 184,915
Allowance for borrowed funds used during
construction and capitalized interest (9,523) (4,159) (2,096)
Other interest expense 31,451 31,971 34,976
Subsidiaries' preferred stock dividend
requirements 14,504 15,170 15,426
---------- ---------- ----------
Net interest charges 201,841 221,199 233,221
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 336,456 297,689 301,320
EXTRAORDINARY ITEM (NET OF INCOME TAXES)
(Note 1) -- -- (30,522)
---------- ---------- ----------
NET INCOME 336,456 297,689 270,798
PREFERRED STOCK DIVIDEND REQUIREMENTS 11,124 11,547 11,970
---------- ---------- ----------
EARNINGS ON COMMON STOCK $ 325,332 $ 286,142 $ 258,828
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999
- ---------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $4,930,844 $8,118,783
Less-Accumulated provision for depreciation 2,376,457 3,713,781
---------- ----------
2,554,387 4,405,002
---------- ----------
Construction work in progress-
Electric plant 219,623 205,671
Nuclear Fuel 18,898 10,059
---------- ----------
238,521 215,730
---------- ----------
2,792,908 4,620,732
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust (Note 2) 452,128 469,124
Letter of credit collateralization (Note 2) 277,763 277,763
Nuclear plant decommissioning trusts 262,042 236,903
Long-term notes receivable from associated companies
(Note 3B) 351,545 145,675
Other 305,848 280,197
---------- ----------
1,649,326 1,409,662
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 18,269 87,175
Receivables-
Customers (less accumulated provisions of $11,777,000
and $6,452,000, respectively, for uncollectible
accounts) 304,719 278,484
Associated companies 478,025 221,653
Other (less accumulated provision of $1,000,000 for
uncollectible accounts at both dates) 34,281 36,281
Materials and supplies, at average cost-
Owned 80,534 69,119
Under consignment 51,488 55,278
Prepayments and other 76,934 73,682
---------- ----------
1,044,250 821,672
---------- ----------
DEFERRED CHARGES:
Regulatory assets 2,498,837 1,618,319
Property taxes 56,429 100,906
Unamortized sale and leaseback costs 80,103 85,100
Other 32,298 44,355
---------- ----------
2,667,667 1,848,680
---------- ----------
$8,154,151 $8,700,746
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of
Capitalization):
Common stockholder's equity $2,556,992 $2,624,460
Preferred stock-
Not subject to mandatory redemption 160,965 160,965
Subject to mandatory redemption -- 5,000
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption 39,105 39,105
Subject to mandatory redemption 15,000 15,000
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely
Company subordinated debentures 120,000 120,000
Long-term debt 2,000,622 2,175,812
---------- ----------
4,892,684 5,140,342
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock 311,358 422,838
Short-term borrowings (Note 4)-
Associated companies 19,131 35,583
Other 296,301 322,713
Accounts payable-
Associated companies 123,859 50,883
Other 60,332 63,219
Accrued taxes 232,225 207,362
Accrued interest 34,106 37,572
Other 75,288 94,967
---------- ----------
1,152,600 1,235,137
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 1,298,845 1,468,478
Accumulated deferred investment tax credits 110,064 143,336
Nuclear plant decommissioning costs 261,204 239,695
Other postretirement benefits 160,719 148,421
Other 278,035 325,337
---------- ----------
2,108,867 2,325,267
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5) ---------- ----------
$8,154,151 $8,700,746
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these balance sheets.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
(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
Retained earnings (Note 3A) 458,263 525,731
---------- ----------
Total common stockholder's equity 2,556,992 2,624,460
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
----------------- -------------------
2000 1999 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3C):
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 4,000,000 25.00 100,000 100,000 100,000
--------- --------- -------- ---------- ----------
Total Not Subject to
Mandatory Redemption 4,609,650 4,609,650 $163,893 160,965 160,965
========= ========= ======== ---------- ----------
Cumulative, $100 par value-
Subject to Mandatory Redemption
(Note 3D):
8.45% 50,000 100,000 5,000 10,000
Redemption Within One Year (5,000) (5,000)
--------- --------- ---------- ----------
Total Subject to
Mandatory Redemption 50,000 100,000 -- 5,000
========= ========= ---------- ----------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARY (Note 3C):
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 3D):
7.625% 150,000 150,000 105.34 $ 15,801 15,000 15,000
========= ========= ======== ---------- ----------
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY COMPANY SUBORDINATED
DEBENTURES (Note 3E):
Cumulative, $25 par value-
Authorized 4,800,000 shares
Subject to Mandatory Redemption:
9.00% 4,800,000 4,800,000 120,000 120,000
========= ========= ---------- ----------
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2000 1999 2000 1999 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Note 3F):
First mortgage bonds:
Ohio Edison Company- Pennsylvania Power Company-
6.375% due 2000 -- 80,000 9.740% due 2001-2019 18,539 19,513
7.375% due 2002 120,000 120,000 7.500% due 2003 40,000 40,000
7.500% due 2002 34,265 34,265 6.375% due 2004 20,500 20,500
8.250% due 2002 125,000 125,000 6.625% due 2004 14,000 14,000
8.625% due 2003 150,000 150,000 8.500% due 2022 27,250 27,250
6.875% due 2005 80,000 80,000 7.625% due 2023 6,500 6,500
8.750% due 2022 50,960 50,960 -------- -------
7.625% due 2023 75,000 75,000
7.875% due 2023 93,500 93,500
------- -------
Total first mortgage bonds. 728,725 808,725 126,789 127,763 855,514 936,488
------- ------- -------- -------- ---------- ----------
Secured notes:
Ohio Edison Company- Pennsylvania Power Company-
7.450% due 2000 -- 47,725 6.080% due 2000 -- 23,000
8.100% due 2000 -- 30,000 8.100% due 2000 -- 5,200
7.930% due 2002 15,887 28,386 5.400% due 2013 1,000 1,000
7.680% due 2005 200,000 200,000 5.400% due 2017 10,600 10,600
*4.650% due 2015 19,000 -- 7.150% due 2017 17,925 17,925
6.750% due 2015 40,000 40,000 5.900% due 2018 16,800 16,800
7.100% due 2018 -- 26,000 7.150% due 2021 14,482 14,482
7.050% due 2020 60,000 60,000 6.150% due 2023 12,700 12,700
7.000% due 2021 69,500 69,500 *5.050% due 2027 10,300 10,300
7.150% due 2021 443 443 6.450% due 2027 14,500 14,500
5.375% due 2028 13,522 13,522 5.375% due 2028 1,734 1,734
5.625% due 2029 50,000 50,000 5.450% due 2028 6,950 6,950
5.950% due 2029 56,212 56,212 6.000% due 2028 14,250 14,250
*4.650% due 2030 60,400 -- 5.950% due 2029 238 238
*4.700% due 2033 57,100 -- ------- -------
5.450% due 2033 14,800 14,800
Limited Partnerships-
7.81% weighted average
interest rate due 2000-2007 24,287 12,574
------- -------
681,151 649,162 121,479 149,679 802,630 798,841
------- ------- ------- ------- ---------- ----------
OES Fuel-
7.10% weighted average
interest rate 91,620 81,260
---------- ----------
Total secured notes 894,250 880,101
---------- ----------
Unsecured notes:
Ohio Edison Company- Pennsylvania Power Company-
* 7.475% due 2002 25,000 -- *5.900% due 2033 5,200 5,200
* 7.413% due 2002 75,000 -- ------- -------
* 7.300% due 2002 -- 140,000
* 8.113% due 2002 -- 50,000
* 4.300% due 2012 -- 50,000
* 4.800% due 2014 50,000 50,000
* 4.100% due 2015 50,000 50,000
* 5.800% due 2016 47,725 47,725
* 4.200% due 2018 -- 57,100
* 5.000% due 2018 56,000 56,000
* 4.900% due 2023 50,000 --
* 3.100% due 2032 -- 53,400
* 4.250% due 2033 50,000 50,000
* 4.650% due 2033 108,000 108,000
* 5.400% due 2033 30,000 30,000
------- --------
Total unsecured notes 541,725 742,225 5,200 5,200 546,925 747,425
------- ------- ------- ------- ---------- ----------
Capital lease obligations (Note 2) 12,961 33,852
---------- ----------
Net unamortized discount on debt (2,670) (4,216)
---------- ----------
Long-term debt due within one year (306,358) (417,838)
---------- ----------
Total long-term debt 2,000,622 2,175,812
---------- ----------
TOTAL CAPITALIZATION $4,892,684 $5,140,342
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2000 interest rate
shown for only December 31, 2000 balances and December 31, 1999
interest rate shown for only December 31, 1999 balances.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Other
Comprehensive
Comprehensive Number Carrying Income Retained
Income of Shares Value (Loss) Earnings
------------- --------- --------- --------------- ---------
(Dollars in thousands)
Balance, January 1, 1998 100 $2,103,260 $ (615) $621,674
Net income $270,798 270,798
Transfer of minimum liability for
unfunded retirement benefits to
parent 615 615
--------
Comprehensive income $271,413
========
Transfer of ESOP premium to parent (4,531)
Cash dividends on preferred stock (11,952)
Cash dividends on common stock (297,376)
- ----------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 100 2,098,729 -- 583,144
Net income $297,689 297,689
========
Transfer of Penn Power Energy
to FirstEnergy Services Corp. 3,302
Cash dividends on preferred stock (11,401)
Cash dividends on common stock (347,003)
- ----------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 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
================================================================================================================
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, 1998 5,118,699 $211,870 5,150,000 $155,000
Redemptions-
8.45% Series (50,000) (5,000)
- ---------------------------------------------------------------------------------------------------
Balance, December 31, 1998 5,118,699 211,870 5,100,000 150,000
Redemptions-
7.64% Series (60,000) (6,000)
8.00% Series (58,000) (5,800)
8.45% Series (50,000) (5,000)
- ---------------------------------------------------------------------------------------------------
Balance, December 31, 1999 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
===================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 336,456 $ 297,689 $ 270,798
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 578,679 582,197 411,979
Nuclear fuel and lease amortization 52,232 45,850 35,086
Deferred income taxes, net (110,038) (120,149) (55,817)
Investment tax credits, net (25,035) (13,793) (14,290)
Extraordinary item -- -- 51,730
Receivables (279,575) (43,623) (144,549)
Materials and supplies (7,625) 18,257 (1,627)
Accounts payable 70,089 14,443 (8,455)
Other 8,753 14,442 64,552
--------- --------- ---------
Net cash provided from operating activities 623,936 795,313 609,407
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 207,283 242,601 117,265
Short-term borrowings, net -- 20,113 35,954
Redemptions and Repayments-
Preferred stock 5,000 17,005 5,000
Long-term debt 485,178 396,410 225,241
Short-term borrowings, net 42,864 -- --
Dividend Payments-
Common stock 392,800 347,003 297,746
Preferred stock 11,124 11,512 11,865
--------- --------- ---------
Net cash used for financing activities 729,683 509,216 386,633
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 279,508 237,199 186,139
Loans to associated companies 206,901 -- --
Sale of assets to associated companies (531,633) -- --
Other 8,383 (5,064) 8,102
--------- --------- ---------
Net cash used for (provided from) investing
activities (36,841) 232,135 194,241
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents (68,906) 53,962 28,533
Cash and cash equivalents at beginning of year 87,175 33,213 4,680
--------- --------- ---------
Cash and cash equivalents at end of year $ 18,269 $ 87,175 $ 33,213
========= ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $ 183,117 $ 203,749 $ 201,064
========= ========= =========
Income taxes $ 305,644 $ 308,052 $ 219,226
========= ========= =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 103,741 $ 111,222 $ 116,868
State gross receipts 104,851 106,926 104,175
Social security and unemployment 11,964 14,432 12,701
Other 5,293 7,701 8,780
---------- ---------- ----------
Total general taxes $ 225,849 $ 240,281 $ 242,524
========== ========== ==========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 329,616 $ 307,462 $ 229,164
State 18,037 18,315 14,732
---------- ---------- ----------
347,653 325,777 243,896
---------- ---------- ----------
Deferred, net-
Federal (102,692) (113,347) (50,310)
State (7,346) (6,802) (5,507)
---------- ---------- ----------
(110,038) (120,149) (55,817)
---------- ---------- ----------
Investment tax credit amortization (25,035) (13,793) (14,290)
---------- ---------- ----------
Total provision for income taxes $ 212,580 $ 191,835 $ 173,789
========== ========== ==========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income $ 198,436 $ 170,872 $ 174,692
Other income 14,144 20,963 20,305
Extraordinary item -- -- (21,208)
---------- ---------- ----------
Total provision for income taxes $ 212,580 $ 191,835 $ 173,789
========== ========== ==========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 549,036 $ 489,524 $ 444,587
========== ========== ==========
Federal income tax expense at statutory rate $ 192,163 $ 171,333 $ 155,605
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (25,035) (13,793) (14,290)
State income taxes, net of federal income tax benefit 6,949 7,483 5,996
Amortization of tax regulatory assets 39,746 24,950 29,961
Other, net (1,243) 1,862 (3,483)
---------- ---------- ----------
Total provision for income taxes $ 212,580 $ 191,835 $ 173,789
========== ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences $ 377,521 $ 847,479 $ 880,645
Allowance for equity funds used during construction 62,604 152,846 169,780
Deferred nuclear expense 220,123 229,366 237,602
Impaired generating assets 439,987 -- --
Competitive transition charge 95,497 115,277 135,730
Customer receivables for future income taxes 68,624 163,500 164,618
Deferred sale and leaseback costs (30,151) (26,966) 45,521
Unamortized investment tax credits (39,369) (51,521) (55,495)
Deferred gain for asset sale to affiliated company 73,312 -- --
Other 30,697 38,497 23,486
---------- ---------- ----------
Net deferred income tax liability $1,298,845 $1,468,478 $1,601,887
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
<PAGE
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). FirstEnergy
holds directly all of the issued and outstanding common shares of the
Company and its other principal electric utility operating subsidiaries,
The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison
Company (TE). On September 1, 2000, the Company and Penn (Companies) sold
their transmission assets to FirstEnergy's wholly owned subsidiary,
American Transmission Systems, Inc. (ATSI). As a result, ATSI owns and
operates FirstEnergy's major high-voltage transmission facilities and has
interconnections with other regional utilities.
The Companies follow the accounting policies and practices
prescribed by 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.
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, 2000 or 1999, with respect to any particular
segment of the Companies' customers.
REGULATORY PLANS-
The PUCO approved the Company's Rate Reduction and Economic
Development Plan in 1995. This regulatory plan was to maintain then
current base electric rates for the Company through December 31, 2005. At
the end of the regulatory plan period, the Company's base rates were to be
reduced by $300 million (approximately 20 percent below then current
levels). The plan also revised the Company's fuel cost recovery method so
that the Company's fuel rates would be frozen through the regulatory plan
period, subject to limited periodic adjustments. As part of the Company's
regulatory plan, transition rate credits were implemented for customers,
which were expected to reduce operating revenues for the Company by
approximately $600 million during the regulatory plan period. The
regulatory plan was terminated at the end of 2000 concurrent with the
implementation of the FirstEnergy transition plan as described further
below.
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 provides for a five percent 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. 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.
FirstEnergy, on behalf of its Ohio electric utility operating
companies -- the Company, CEI and TE -- filed its transition plan under
Ohio's new electric utility restructuring law in late 1999. The filing
also included additional information on FirstEnergy's plans to turn over
control, and perhaps ownership, of its transmission assets to the Alliance
Regional Transmission Organization. The transition plan itemized, or
unbundled, the current price of electricity into its component
elements -- including generation, transmission, distribution and
transition charges. As required by the PUCO's rules, FirstEnergy's
transition plan also included its proposals on corporate separation of its
regulated and unregulated operations, operational and technical support
changes needed to accommodate customer choice, an education program to
inform customers of their options under the new law, and how FirstEnergy's
transmission system will be operated to ensure access to all users.
Customer prices would be frozen through a five-year market development
period (2001-2005), except for certain limited statutory exceptions
including the five percent reduction in the price of generation for
residential customers. The plan proposed recovery of the Company's
generation-related transition costs of approximately $1.8 billion
($1.6 billion, net of deferred income taxes) and its transition costs
related to regulatory assets aggregating approximately $1.5 billion
($1.0 billion, net of deferred income taxes).
On July 19, 2000, the PUCO approved FirstEnergy's transition plan
as modified by a settlement agreement with major parties to the transition
plan. Major parties to the settlement agreement included the PUCO staff, the
Ohio Consumers' Counsel, the Industrial Energy Users-Ohio, certain power
marketers and others. Major provisions of the settlement agreement consisted
of approval of recovery of transition costs in the amounts filed in the
transition plan through no later than 2006 for the Company, except where a
longer period of recovery is provided for in the settlement agreement. The
Company will also give preferred access over FirstEnergy's subsidiaries to
nonaffiliated marketers, brokers and aggregators to 560 megawatts of
generation capacity through 2005 at established prices for sales to the
Company's retail customers. The base electric rates for distribution service
for the Company under its prior regulatory plan will be extended from
December 31, 2005 through December 31, 2007. The transition rate credits for
customers under its prior regulatory plan will also be extended through the
transition cost recovery period.
The application of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71), to the Company's generation business was discontinued with the
issuance of the PUCO transition plan order. The Securities and Exchange
Commission (SEC) issued interpretive guidance regarding asset impairment
measurement that concluded 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.
The settlement agreement provides to the Company's customers an
additional incentive applied to the generation shopping credit of 45% for
residential customers, 30% for commercial customers and 15% for industrial
customers as reductions from their bills, when they select alternative
energy providers (the credits exceed the price the Company will be offering
to electricity suppliers relating to the 560 megawatts described above).
The amount of the incentive will serve to reduce the amortization of
transition costs during the market development period and will be recovered
over the remaining transition cost recovery period. If the customer
switching targets established in the settlement agreement are not achieved
by the end of 2005, the transition cost recovery period could be shortened
for the Company to reduce recovery by as much as $250 million, but any such
adjustment would be computed on a class-by-class and pro-rata basis.
In June 1998, the PPUC authorized a rate restructuring plan for
Penn, which essentially resulted in the deregulation of Penn's generation
business as of June 30, 1998. Penn was required to remove from its balance
sheet all regulatory assets and liabilities related to its generation
business and assess all other assets for impairment. In accordance with
the SEC guidance, Penn reduced its nuclear generating unit investments by
approximately $305 million, of which approximately $227 million was
recognized as a regulatory asset to be recovered through a CTC over a
seven-year transition period; the remaining net amount of $78 million was
written off. The charge of $51.7 million ($30.5 million after income
taxes) for discontinuing the application of SFAS 71 to Penn's generation
business was recorded as a 1998 extraordinary item on the Consolidated
Statement of Income.
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, 2000 were
$1.075 billion and $7.422 billion, respectively, for the Company and
$92 million and $989 million, respectively, for Penn.
All of the Companies' regulatory assets will continue to be
recovered under provisions of the Ohio transition plan and the
Pennsylvania rate restructuring plan. Under the previous regulatory plan,
the PUCO had authorized the Company to recognize additional capital
recovery related to its generating assets (which was reflected as
additional depreciation expense) and additional amortization of regulatory
assets during the prior regulatory plan period of at least $2 billion, and
the PPUC had authorized Penn to accelerate at least $358 million more than
the amounts that would have been recognized if the prior regulatory plans
were not in effect. These additional amounts are being recovered through
current rates. As of December 31, 2000, the Companies' cumulative
additional capital recovery and regulatory asset amortization amounted to
$1.424 billion (including Penn's impairment discussed above and CTC
recovery).
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 as discussed above), including payroll and related costs such as
taxes, employee benefits, administrative and general costs, and interest
costs.
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 2.8% in 2000 and 3.0% in 1999 and 1998. The annual composite
rate for Penn's electric plant was approximately 2.6% in 2000, 2.5% in
1999 and 3.0% in 1998. In addition to the straight-line depreciation
recognized in 2000, 1999 and 1998, the Companies recognized additional
capital recovery of $105 million, $95 million and $141 million (excluding
Penn's impairment), respectively, as additional depreciation expense in
accordance with their regulatory plans. These amounts were included in the
2000 transfer of accumulated depreciation included in the Company's
impaired plant investment recognized as regulatory assets as discussed in
"Regulatory Plans" above.
Annual depreciation expense in 2000 included approximately
$7.8 million for future decommissioning costs applicable to the Companies'
ownership and leasehold interests in three nuclear generating units.
Annual decommissioning costs will increase by approximately $28 million
from implementing the Company's transition plan in 2001. The Companies'
future decommissioning costs reflect the 1999 increase in Penn's ownership
interest related to the exchange of certain generating assets with
Duquesne Light Company. The Companies' share of the future obligation to
decommission these units is approximately $777 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 begins. The Companies
have recovered approximately $97 million for decommissioning through their
electric rates from customers through December 31, 2000. The Companies
have also recognized an estimated liability of approximately $15.7 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.
The Financial Accounting Standards Board (FASB) issued a
proposed accounting standard for nuclear decommissioning costs in 1996. If
the standard is adopted as proposed: (1) annual provisions for
decommissioning could change; (2) the net present value of estimated
decommissioning costs could be recorded as a liability; and (3) income
from the external decommissioning trusts could be reported as investment
income. The FASB subsequently expanded the scope of the proposed standard
to include other closure and removal obligations related to long-lived
assets. A final pronouncement is expected in the second quarter of 2001
and is anticipated to be implemented on January 1, 2002.
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, 2000
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 $ 345.0 $ 145.8 $ 0.6 68.80%
Bruce Mansfield #1,
#2 and #3 985.2 555.3 0.1 67.18%
Beaver Valley
#1 and #2 46.7 10.1 18.5 77.81%
Perry 319.7 307.3 10.0 35.24%
- ------------------------------------------------------------------------
Total $1,696.6 $1,018.5 $29.2
========================================================================
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.
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.
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. 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, 2000. 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
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.
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
---------------- -------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------
(In millions)
Change in benefit
obligation:
Benefit obligation as of January 1 $1,394.1 $1,500.1 $ 608.4 $ 601.3
Service cost 27.4 28.3 11.3 9.3
Interest cost 104.8 102.0 45.7 40.7
Plan amendments 41.3 -- -- --
Actuarial loss (gain) 17.3 (155.6) 121.7 (17.6)
Net increase from asset swap -- 14.8 -- 12.5
Voluntary early retirement program expense 23.4 -- -- --
Benefits paid (102.2) (95.5) (35.1) (37.8)
- -------------------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,506.1 1,394.1 752.0 608.4
- -------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan
assets as of January 1 1,807.5 1,683.0 4.9 3.9
Actual return on plan assets 0.7 220.0 (0.2) 0.6
Company contribution -- -- 18.3 0.4
Benefits paid (102.2) (95.5) -- --
- -------------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 1,706.0 1,807.5 23.0 4.9
- -------------------------------------------------------------------------------------------------
Funded status of plan 199.9 413.4 (729.0) (603.5)
Unrecognized actuarial loss (gain) (90.9) (303.5) 147.3 24.9
Unrecognized prior service cost 93.1 57.3 20.9 24.1
Unrecognized net transition obligation (asset) (2.1) (10.1) 110.9 120.1
- -------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 200.0 $ 157.1 $(449.9) $(434.4)
=================================================================================================
Companies' share of prepaid (accrued)
benefit cost $ 213.9 $ 194.8 $(157.0) $(145.7)
=================================================================================================
Assumptions used as of December 31:
Discount rate 7.75% 7.75% 7.75% 7.75%
Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
FirstEnergy's net pension and other postretirement benefit costs
for the three years ended December 31, 2000 were computed as follows:
Other
Pension Benefits Postretirement Benefits
------------------------- -------------------------
2000 1999 1998 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------
(In millions)
Service cost $ 27.4 $ 28.3 $ 25.0 $11.3 $ 9.3 $ 7.5
Interest cost 104.8 102.0 92.5 45.7 40.7 37.6
Expected return on plan assets (181.0) (168.1) (152.7) (0.5) (0.4) (0.3)
Amortization of transition obligation (asset) (7.9) (7.9) (8.0) 9.2 9.2 9.2
Amortization of prior service cost 5.7 5.7 2.3 3.2 3.3 (0.8)
Recognized net actuarial loss (gain) (9.1) -- (2.6) -- -- --
Voluntary early retirement program expense 17.2 -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------
Net benefit cost $ (42.9) $ (40.0) $ (43.5) $68.9 $62.1 $53.2
==============================================================================================================
Companies' share of total plan costs $ (19.1) $ (16.9) $ (39.7) $24.7 $25.5 $31.2
- ------------------------------------------------------------------------------------------------------------
The FirstEnergy plan's health care trend rate assumption is 7.2%
in 2001, 7.0% in 2002 and 6.5% in 2003, trending to 5.0% - 5.5% 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 trend rate assumption by one percentage point would increase the
total service and interest cost components by $7.5 million and the
postretirement benefit obligation by $94.4 million. A decrease in the same
assumption by one percentage point would decrease the total service and
interest cost components by $8.5 million and the postretirement benefit
obligation by $111.0 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues and operating expenses include transactions
with CEI and TE, which were primarily for electric sales and ATSI
transmission rent expense of $32.4 million starting in 2000. The amounts
related to CEI and TE were $53.4 million and $15.9 million, respectively,
for 2000, $27.7 million and $18.1 million, respectively, for 1999 and
$17.8 million and $12.7 million, respectively, for 1998. Other income
included $5.4 million of interest income from ATSI beginning in 2000.
FirstEnergy provides support services at cost to the Companies
and other affiliated companies, for which the Companies were billed
$119.0 million, $118.2 million and $114.2 million in 2000, 1999 and 1998,
respectively.
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. As of December 31, 1999, cash and cash
equivalents included $83 million used for the redemption of long-term debt
in the first quarter of 2000. The Companies reflect temporary cash
investments at cost, which approximates their market value. Noncash
financing and investing activities included capital lease transactions
amounting to $1.3 million, $1.4 million and $1.6 million for the years
2000, 1999 and 1998, respectively. Commercial paper transactions of OES
Fuel, Incorporated (OES Fuel) (a wholly owned subsidiary of the Company)
that have initial maturity periods of three months or less are reported
net within financing activities under long-term debt and are reflected as
long-term debt on the Consolidated Balance Sheets (see Note 3F).
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:
2000 1999
- -----------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- -----------------------------------------------------------------------
(In millions)
Long-term debt $2,205 $2,257 $2,483 $2,459
Preferred stock $ 140 $ 138 $ 145 $ 142
Investments other than cash
and cash equivalents:
Debt securities
- Maturity (5-10 years) $ 460 $ 441 $ 475 $ 476
- Maturity (more than
10 years) 464 512 258 267
Equity securities 13 13 14 14
All other 342 341 301 311
- ------------------------------------------------------------------------
$1,279 $1,307 $1,048 $1,068
========================================================================
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. Unrealized gains and losses applicable
to the decommissioning trusts have been recognized in the trust investment
with corresponding changes to the decommissioning liability. The Companies
have no securities held for trading purposes.
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 will 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 also recognized additional cost recovery of $270 million,
$257 million and $50 million in 2000, 1999 and 1998, respectively, as
additional regulatory asset amortization in accordance with their
regulatory plans. The application of SFAS 71 to the Company's generation
business was discontinued effective with the PUCO's approval of
FirstEnergy's transition plan. The effect of such discontinuance was
reflected on the financial statements as of June 30, 2000, with the
reduction of plant investment and the corresponding recognition of
regulatory assets recoverable through future regulatory cash flows for
generating assets that were impaired of approximately $1.2 billion for the
Company.
Regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2000 1999
- -----------------------------------------------------------------
(In millions)
Impaired generating assets $1,238.1 $ --
Nuclear unit expenses 619.4 643.0
Customer receivables for future
income taxes 190.3 455.3
Competitive transition charge 230.9 280.4
Sale and leaseback costs 113.6 120.5
Loss on reacquired debt 80.1 79.7
Employee postretirement benefit costs 20.7 24.8
Other 5.7 14.6
- -------------------------------------------------------------------
Total $2,498.8 $1,618.3
===================================================================
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 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 renewal term (if elected) 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 (OES Finance), 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 pledged to the
financial institution providing those letters of credit are the sole
property of OES Finance. 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, 2000, are summarized as follows:
2000 1999 1998
- ---------------------------------------------------
(In millions)
Operating leases
Interest element $107.0 $108.5 $110.0
Other 35.1 34.4 28.9
Capital leases
Interest element 2.5 5.3 5.3
Other 2.6 4.4 4.8
- ---------------------------------------------------
Total rentals $147.2 $152.6 $149.0
===================================================
The future minimum lease payments as of December 31, 2000, are:
Operating Leases
--------------------------------
Capital Lease PNBV Capital
Leases Payments Trust Net
- ----------------------------------------------------------------
(In millions)
2001 $ 5.3 $ 127.1 $ 59.5 $ 67.6
2002 4.8 130.4 61.0 69.4
2003 4.5 136.9 62.6 74.3
2004 4.4 137.7 58.3 79.4
2005 4.4 138.6 56.3 82.3
Years thereafter 8.6 1,551.7 474.6 1,077.1
- ------------------------------------------------------------------
Total minimum
lease payments 32.0 $2,222.4 $772.3 $1,450.1
Executory costs 10.6 ======== ====== ========
- ---------------------------
Net minimum lease
payments 21.4
Interest portion 8.4
- ---------------------------
Present value of net
minimum lease
payments 13.0
Less current portion 2.2
- ---------------------------
Noncurrent portion $10.8
===========================
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 $409.8 million at December 31, 2000.
(B) EMPLOYEE STOCK OWNERSHIP PLAN-
FirstEnergy funds the matching contribution for its 401(k)
savings plan through an ESOP Trust. 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 (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, 2000 and 1999 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) PREFERRED AND PREFERENCE STOCK-
Penn's 7.75% series of preferred stock has a restriction which
prevents early redemption prior to July 2003. The Company's 8.45% series
of preferred stock has no optional redemption provision. 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.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
The Company's 8.45% series of preferred stock has an annual
sinking fund requirement for 50,000 shares. Penn's 7.625% series has an
annual sinking fund requirement for 7,500 shares beginning on October 1,
2002.
The Companies' preferred shares are retired at $100 per share
plus accrued dividends. Annual sinking fund requirements are $5 million in
2001 and $1 million in each year 2002-2005.
(E) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES-
Ohio Edison Financing Trust, a wholly owned subsidiary of the
Company, has issued $120 million of 9% Cumulative Trust Preferred Capital
Securities. The Company purchased all of the Trust's Common Securities and
simultaneously issued to the Trust $123.7 million principal amount of 9%
Junior Subordinated Debentures due 2025 in exchange for the proceeds that
the Trust received from its sale of Preferred and Common Securities. The
sole assets of the Trust are the Subordinated Debentures whose interest
and other payment dates coincide with the distribution and other payment
dates on the Trust Securities. Under certain circumstances the
Subordinated Debentures could be distributed to the holders of the
outstanding Trust Securities in the event the Trust is liquidated. The
Subordinated Debentures may be optionally redeemed by the Company at a
redemption price of $25 per Subordinated Debenture plus accrued interest,
in which event the Trust Securities will be redeemed on a pro rata basis
at $25 per share plus accumulated distributions. The Company's obligations
under the Subordinated Debentures along with the related Indenture,
amended and restated Trust Agreement, Guarantee Agreement and the
Agreement for expenses and liabilities, constitute a full and
unconditional guarantee by the Company of payments due on the Preferred
Securities.
(F) LONG-TERM DEBT-
The first mortgage indentures and their supplements, which
secure all of the Companies' first mortgage bonds, serve as direct first
mortgage liens on substantially all property and franchises, other than
specifically excepted property, owned by the Companies.
Based on the amount of bonds authenticated by the Trustees
through December 31, 2000, the Companies' annual sinking and improvement
fund requirements for all bonds issued under the mortgage amounts to
$31 million. The Companies expect to deposit funds in 2001 that will be
withdrawn upon the surrender for cancellation of a like principal amount
of bonds, which are 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)
- ----------------------------
2001 $304.2
2002 515.6
2003 247.7
2004 257.0
2005 135.4
- ----------------------------
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 $225.1 million and noncancelable
municipal bond insurance policies of $136.5 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, the Companies are entitled
to a credit against their obligation to repay those bonds. The Companies
pay annual fees of 0.60% to 1.25% of the amounts of the letters of credit
to the issuing banks and are obligated to reimburse the banks for any
drawings thereunder.
The Company had unsecured borrowings of $100 million as of
December 31, 2000, supported by a $250 million long-term revolving credit
facility agreement which expires November 18, 2002. The Company must pay
an annual facility fee of 0.20% on the total credit facility amount. In
addition, the credit agreement provides that the Company maintain unused
first mortgage bond capability for the full credit agreement amount under
the Company's indenture as potential security for the unsecured
borrowings.
Nuclear fuel purchases are financed through the issuance of OES
Fuel commercial paper and loans, both of which are supported by a
$180.5 million long-term bank credit agreement which expires March 31,
2001. The Company intends to extend the credit agreement through March 31,
2002. Accordingly, a portion of the commercial paper and loans is
reflected as long-term debt on the Consolidated Balance Sheets. OES Fuel
must pay an annual facility fee of 0.20% on the total line of credit and
an annual commitment fee of 0.0625% on any unused amount.
4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding as of December 31, 2000,
consisted of $136.4 million of bank borrowings and $159.9 million of OES
Capital, Incorporated (OES Capital) 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 2002. As of December 31, 2000, the Company also had total
short-term borrowings of $19.1 million from its affiliates.
The Company has lines of credit with domestic banks that provide
for borrowings of up to $55 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 0.15% to 0.20%. These lines
expire at various times during 2001. The weighted average interest rates
on short-term borrowings outstanding as of December 31, 2000 and 1999,
were 6.93% and 6.27%, respectively.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Companies' current forecasts reflect expenditures of
approximately $513 million for property additions and improvements from
2001-2005, of which approximately $118 million is applicable to 2001.
Investments for additional nuclear fuel during the 2001-2005 period are
estimated to be approximately $187 million, of which approximately
$39 million applies to 2001. During the same periods, the Companies'
nuclear fuel investments are expected to be reduced by approximately
$217 million and $45 million, respectively, as the nuclear fuel is
consumed.
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
$168.2 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 $358 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 $17.7 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.
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.
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 $27,500 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 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 twenty-two
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. In March
2000, the U.S. Court of Appeals for the D.C. Circuit upheld EPA's NOx
Transport Rule except as applied to the State of Wisconsin and portions of
Georgia and Missouri. By October 2000, states were to submit revised State
Implementation Plans (SIP) to comply by May 31, 2004 with individual state
NOx budgets established by the EPA. Pennsylvania recently submitted a SIP
that requires compliance with the NOx budgets at the Companies'
Pennsylvania facilities by May 1, 2003 and Ohio submitted a "draft" SIP
that requires compliance with the NOx budgets at the Companies' Ohio
facilities by May 31, 2004. A Federal Implementation Plan accompanied the
NOx Transport Rule and may be implemented by the EPA in states which fail
to revise their SIP. In another separate but related action, eight states
filed petitions with the EPA under Section 126 of the Clean Air Act
seeking reductions of NOx emissions which are alleged to contribute to
ozone pollution in the eight petitioning states. The EPA position is that
the Section 126 petitions will be adequately addressed by the NOx
Transport Program, but a December 17, 1999 rulemaking established an
alternative program which would require nearly identical 85% NOx
reductions at 392 utility plants, including the Companies' Ohio and
Pennsylvania plants, by May 2003, in the event implementation of the NOx
Transport Rule is not implemented by a state. Additional Section 126
petitions were filed by New Jersey, Maryland, Delaware and the District of
Columbia in mid-1999 and are still under evaluation by the EPA.
FirstEnergy continues to evaluate its compliance plans and other
compliance options.
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 on the manner in which they are ultimately
implemented, if at all, 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. 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.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from
electric power plants. The EPA identified mercury as the hazardous air
pollutant of greatest concern. The EPA established a schedule to propose
regulations by December 2003 and issue final regulations by December 2004.
The future cost of compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of
1976, as amended, and the Toxic Substances Control Act of 1976, federal
and state hazardous waste regulations have been promulgated. Certain
fossil-fuel combustion waste products, such as coal ash, were exempted
from hazardous waste disposal requirements pending the EPA's evaluation of
the need for future regulation. The EPA has issued its final regulatory
determination that regulation of coal ash as a hazardous waste is
unnecessary. On April 25, 2000, the EPA announced that it will develop
national standards regulating disposal of coal ash under its authority to
regulate nonhazardous waste.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2000 and 1999.
March 31, June 30, September 30, December 31,
Three Months Ended 2000 2000 2000 2000
- ------------------------------------------------------------------------
(In millions)
Operating Revenues $644.4 $667.2 $733.9 $681.2
Operating Expenses
and Taxes 524.9 533.1 604.6 581.8
- ----------------------------------------------------------------------
Operating Income 119.5 134.1 129.3 99.4
Other Income 12.3 11.5 16.4 15.8
Net Interest Charges 51.0 51.8 51.4 47.6
- ----------------------------------------------------------------------
Net Income $ 80.8 $ 93.8 $ 94.3 $ 67.6
======================================================================
Earnings on Common
Stock $ 78.0 $ 91.0 $ 91.5 $ 64.8
======================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1999 1999 1999 1999
- ----------------------------------------------------------------------
(In millions)
Operating Revenues $633.1 $646.7 $770.5 $636.6
Operating Expenses
and Taxes 498.1 532.7 650.2 532.8
- ----------------------------------------------------------------------
Operating Income 135.0 114.0 120.3 103.8
Other Income 9.3 13.1 10.2 13.2
Net Interest Charges 56.5 58.4 53.9 52.5
- ----------------------------------------------------------------------
Net Income $ 87.8 $ 68.7 $ 76.6 $ 64.5
======================================================================
Earnings on Common
Stock $ 84.9 $ 65.8 $ 73.7 $ 61.7
======================================================================
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, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
February 16, 2001.
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