Management Report
The consolidated financial statements were prepared by the
management of FirstEnergy Corp., who takes responsibility for their
integrity and objectivity. The statements were prepared in conformity with
accounting principles generally accepted in the United States and are
consistent with other financial information appearing elsewhere in this
report. Arthur Andersen LLP, independent public accountants, have
expressed an unqualified opinion on the Company's consolidated financial
statements.
The Company's internal auditors, who are responsible to the
Audit Committee of the Board of Directors, review the results and
performance of operating units within the Company for adequacy,
effectiveness and reliability of accounting and reporting systems, as well
as managerial and operating controls.
The Audit Committee consists of four nonemployee directors whose
duties include: consideration of the adequacy of the internal controls of
the Company and the objectivity of financial reporting; inquiry into the
number, extent, adequacy and validity of regular and special audits
conducted by independent public accountants and the internal auditors;
recommendation to the Board of Directors of independent accountants to
conduct the normal annual audit and special purpose audits as may be
required; and reporting to the Board of Directors the Committee's findings
and any recommendation for changes in scope, methods or procedures of the
auditing functions. The Committee also reviews the results of management's
programs to monitor compliance with the Company's policies on business
ethics and risk management. The Audit Committee held five meetings in
2000.
Richard H. Marsh
Vice President and
Chief Financial Officer
Harvey L. Wagner
Controller and
Chief Accounting Officer
Report of Independent Public Accountants
To the Stockholders and Board of Directors of FirstEnergy Corp.:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of FirstEnergy Corp. (an Ohio
corporation) and subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of income, common stockholders' 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 FirstEnergy Corp. 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.
FIRSTENERGY CORP.
SELECTED FINANCIAL DATA
For the Years Ended December 31, 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
Revenues $ 7,028,961 $ 6,319,647 $ 5,874,906 $ 2,961,125 $2,521,788
-------------------------------------------------------------
Income Before Extraordinary Item $ 598,970 $ 568,299 $ 441,396 $ 305,774 $ 302,673
-------------------------------------------------------------
Net Income $ 598,970 $ 568,299 $ 410,874 $ 305,774 $ 302,673
-------------------------------------------------------------
Earnings per Share of Common Stock:
Before Extraordinary Item $2.69 $2.50 $1.95 $1.94 $2.10
After Extraordinary Item $2.69 $2.50 $1.82 $1.94 $2.10
-------------------------------------------------------------
Dividends Declared per Share of
Common Stock $1.50 $1.50 $1.50 $1.50 $1.50
-------------------------------------------------------------
Total Assets $17,941,294 $18,224,047 $18,192,177 $18,261,481 $9,218,623
-------------------------------------------------------------
Capitalization at December 31:
Common Stockholders' Equity $ 4,653,126 $ 4,563,890 $ 4,449,158 $ 4,159,598 $2,503,359
Preferred Stock:
Not Subject to Mandatory
Redemption 648,395 648,395 660,195 660,195 211,870
Subject to Mandatory Redemption 161,105 256,246 294,710 334,864 155,000
Long-Term Debt 5,742,048 6,001,264 6,352,359 6,969,835 2,712,760
-------------------------------------------------------------
Total Capitalization $11,204,674 $11,469,795 $11,756,422 $12,124,492 $5,582,989
==============================================================
PRICE RANGE OF COMMON STOCK
FirstEnergy Corp.'s Common Stock is listed on the New York Stock
Exchange and is traded on other registered exchanges.
2000 1999
- --------------------------------------------------------------
First Quarter High-Low 23.56 18.00 33.19 27.94
------------ ------------
Second Quarter High-Low 26.88 20.56 32.13 27.94
------------ ------------
Third Quarter High-Low 27.88 22.94 31.31 24.75
------------ ------------
Fourth Quarter High-Low 32.13 24.11 26.56 22.13
------------ ------------
Yearly High-Low 32.13 18.00 33.19 22.13
- --------------------------------------------------------------
<FN>
Prices are based on reports published in The Wall Street Journal for
-----------------------
New York Stock Exchange Composite Transactions.
HOLDERS OF COMMON STOCK
There were 167,912 and 166,966 holders of 224,531,580 and 223,981,580
shares of the Company's Common Stock as of December 31, 2000 and
January 31, 2001, respectively. Information regarding retained earnings
available for payment of cash dividends is given in Note 4A.
FIRSTENERGY CORP.
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), the availability and cost of capital,
inability to accomplish or realize anticipated benefits of strategic goals
(including our merger with GPU, Inc.) and other similar factors.
Proposed Business Combination
- -----------------------------
On August 8, 2000, FirstEnergy entered into an agreement to
merge with GPU, Inc. (GPU), a Pennsylvania corporation, headquartered in
Morristown, New Jersey. Subsequently, the agreement was overwhelmingly
approved by the shareholders of both companies. All regulatory filings
necessary to complete the merger have since been made. Our target to
complete the merger is by the end of the second quarter of 2001.
Under the merger agreement, we would acquire all the outstanding
shares of GPU's common stock for approximately $4.5 billion in cash and
FirstEnergy common stock. Our cash investment would be financed through
the issuance of about $2.2 billion of new debt. Also, approximately
$7.4 billion of debt and preferred stock of GPU's subsidiaries would
remain outstanding. The transaction would be accounted for by the purchase
method. The combined company's principal electric utility operating
companies would include Ohio Edison Company (OE), The Cleveland Electric
Illuminating Company (CEI), The Toledo Edison Company (TE), Pennsylvania
Power Company (Penn) and American Transmission Systems, Incorporated
(ATSI), as well as GPU's electric utility operating companies - Jersey
Central Power & Light Company, Metropolitan Edison Company and
Pennsylvania Electric Company, which serve customers in Pennsylvania and
New Jersey.
The merger is expected to provide enhanced opportunities for
financial growth, greater scope and size, improved generation efficiency
and broadened unregulated opportunities. The combination will provide a
significant market for our generating capacity and value-added services
and will support our strategic vision of being the premier retail energy
and related services provider in our targeted area for growth - a
thirteen-state region in the northeastern quadrant of the nation.
Competition
We continue to face many competitive challenges as consumers are
provided increasing opportunities to select their electricity suppliers.
As our industry changes to a more competitive environment, we continue to
take actions designed to create a larger, stronger enterprise that will be
better positioned to compete in the changing energy marketplace. As Ohio
approached a new era of customer choice in the selection of energy
suppliers, we continued to develop our regionally-focused retail sales
strategy.
Results of Operations
Net income increased to $599.0 million in 2000, compared to
$568.3 million in 1999 and $410.9 million in 1998. The increase in 2000
resulted primarily from lower fuel costs and increased generation output,
reduced financing costs and gains realized on the sales of emission
allowances. In 1999, higher sales revenues, the absence of unusually high
purchased power costs experienced in 1998 and lower interest costs
contributed to the increase in net income from the prior year.
Additional sales by our unregulated businesses resulted in a
$709.3 million increase in total revenues in 2000 compared to the prior
year. The increase resulted from an expansion of both gas and electric
sales. In 1999, the $444.7 million increase in revenues resulted
substantially from contributions of the Electric Utility Operating
Companies (EUOC) and increases in newly acquired businesses, which were
partially offset by reduced revenues from FirstEnergy Trading Services,
Inc. (FETS) compared to the prior year's results. The sources of the
changes in revenues during 2000 and 1999 are summarized in the following
table.
Sources of Revenue Changes 2000 1999
- ---------------------------------------------------------
Increase (Decrease) (In millions)
EUOC:
Electric sales $(38.5) $213.2
Other electric utility revenues 6.4 3.1
- ---------------------------------------------------------
Total EUOC (32.1) 216.3
- ---------------------------------------------------------
Unregulated Businesses:
Retail electric sales 170.7 54.0
FETS 211.5 (220.1)
Other businesses 359.2 394.5
- ---------------------------------------------------------
Total Unregulated Businesses 741.4 228.4
- ---------------------------------------------------------
Net Revenue Increase $709.3 $444.7
=========================================================
Electric Sales
EUOC electric sales revenues decreased by $32.1 million in 2000,
compared to 1999, as a result of lower unit prices which were partially
offset by increased generation sales volume. Despite a milder summer,
retail electric generation sales were 2.0% higher in 2000 than the
previous year. Total electric generation sales (including unregulated
sales) increased 8.4% in 2000, compared to 1999. Unregulated retail sales
more than tripled from the prior year reflecting continued progress in our
marketing efforts to expand retail electric sales to our targeted
unregulated markets in the eastern seaboard states. Sales to commercial
customers accounted for most of the increase. The cooler summer weather
reduced retail customer demand, making more of our energy available to
serve the wholesale market. As a result, we were able to achieve moderate
growth in kilowatt-hour sales to that market in 2000. EUOC kilowatt-hour
deliveries (to customers in our franchise areas) increased in 2000 from
the prior year due to additional sales to commercial and industrial
customers. Kilowatt-hour sales to residential customers declined. Other
electric utility revenues increased in 2000 from the previous year
primarily due to additional transmission service revenues.
EUOC revenues increased $216.3 million in 1999, compared to
1998, benefiting from increases in kilowatt-hour sales, which were only
partially offset by reduced unit prices. Retail kilowatt-hour sales
increased 2.3%. Total electric generation sales increased 8.0% in 1999
from the prior year due to additional unregulated sales reflecting our
initial expansion into targeted eastern markets and weather-induced demand
in the wholesale market. EUOC kilowatt-hour deliveries to residential,
commercial and industrial customers increased in 1999, compared to 1998,
reflecting a strong consumer-driven economy and warmer weather than the
preceding year.
Changes in electric generation sales and kilowatt-hour
deliveries in 2000 and 1999 are summarized in the following table:
Changes in KWH Sales 2000 1999
- ----------------------------------------------------------
Increase (Decrease)
Electric Generation Sales:
EUOC - Retail 2.0% 2.3%
Unregulated 50.4% 52.0%
- ----------------------------------------------------------
Total Electric Generation Sales 8.4% 8.0%
========================================================
EUOC Distribution Deliveries:
Residential (1.2)% 5.5%
Commercial 2.5% 2.8%
Industrial 3.2% 2.5%
- ----------------------------------------------------------
Total Distribution Deliveries 1.7% 3.4%
==========================================================
Other Sales
Retail natural gas revenues were the largest source of increase
in other business revenues in 2000, compared to 1999. Collectively, three
gas acquisitions in 1999 (Atlas Gas Marketing Inc., Belden Energy Services
Company and Volunteer Energy LLC), as well as increased retail marketing
efforts, significantly expanded retail gas revenues in 2000. Margins were
held down by higher natural gas supply costs but increased activities in
our natural gas exploration and production joint venture, Great Lakes
Energy Partners, helped to offset the lower gas sales margins. FETS also
expanded its wholesale electric and gas revenues in 2000 from prior year
levels. In 1999, FETS revenues decreased significantly compared to the
prior year because of refocusing its activities on supporting our retail
marketing activities. New acquisitions and a one-time gain of $53 million
from the sale of a partnership investment contributed to the increase in
other business revenues in 1999, compared to 1998.
Operating Expenses
Total expenses increased $739.8 million in 2000 and
$255.5 million in 1999, compared to the prior year, primarily reflecting
higher levels of other expenses for EUOC and unregulated operations,
offset in part by lower EUOC fuel and purchased power costs.
Fuel and purchased power decreased $75.7 million in 2000,
compared to 1999. Lower fuel expense accounted for all of the reduction,
declining $103.6 million from 1999, despite a 7% increase in output from
our generating units. Factors contributing to lower fuel expense in 2000
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 western coal and
enhanced the efficiency and cost-competitiveness of our fossil
generation fleet.
Purchased power costs increased $27.9 million in 2000 from the
prior year due to higher average prices and to additional megawatt-hours
purchased. In 1999, fuel and purchased power costs were down
$106.7 million, compared to 1998. The EUOC purchased power costs accounted
for all of the reduction. Much of the improvement was due to the absence
in 1999 of unusual conditions experienced in 1998, which resulted in an
additional $77.4 million of purchased power costs in that year. The 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 several of our power
plants at that time required the EUOC to purchase significant amounts of
power on the spot market. Although above normal temperatures were also
experienced in 1999, the EUOC maintained a stronger capacity position
compared to the previous year and better met customer demand from their
own generation resources.
Other expenses for the EUOC rose $26.6 million in 2000, compared
to 1999, primarily due to additional nuclear refueling costs associated
with three refueling outages in 2000 versus two during the previous year
and increased nuclear ownership resulting from the Duquesne asset swap.
Costs incurred to improve the availability of our fossil generation fleet
and leased portable diesel generators, acquired as part of our summer
supply strategy, added to other expenses for the EUOC in 2000, compared to
1999. Also, we incurred unusual charges in 2000 for early retirement
program costs, as well as increased reserves for potentially uncollectible
accounts for customers in the steel sector who are experiencing
significant financial pressures from foreign steel competition. Partially
offsetting the higher costs were increased gains of $38.5 million realized
from the sale of emission allowances in 2000 as well as nonrecurring costs
recorded in the prior year.
In 1999, other expenses for the EUOC increased from 1998 due to
several factors. Similar to 2000, refueling outage costs and incremental
expenses related to the asset swap, which occurred in early December 1999,
contributed to increase other expenses in 1999 compared to 1998.
Additionally, nuclear costs in 1999 included nonrecurring swap-related
liabilities assumed. Also contributing to the increase were higher
customer, sales and marketing expenses resulting from marketing programs
and information system costs; higher distribution expenses from storm
damage, as well as line and meter maintenance; and a nonrecurring expense
related to a change in employee vacation benefits.
Other expenses for unregulated businesses rose $789.6 million in
2000, compared to 1999. FETS contributed to the increase with its other
expenses rising in line with its higher revenues, reflecting the continued
expansion of its operations to support our retail marketing efforts. FETS
expenses were significantly lower in 1999 due to the absence of costs
incurred in 1998 associated with credit losses and replacement power costs
resulting from the period of sharp price increases in the spot market for
electricity in late June 1998. Refocusing FETS activities in 1999 on
supporting our retail market activities also reduced expenses from the
preceding year.
Acquisitions of three natural gas companies in 1999 and a
general expansion of unregulated sales activity combined to increase the
scope, and therefore, the operating expenses of our unregulated business
activities in 2000. Also, increased reserves for potential uncollectible
accounts were established for customers in the steel sector. In addition,
a $10.5 million reserve was recognized in 2000 for potential construction
contract losses. The acquisitions in the facilities services and natural
gas businesses, as well as costs attributable to unregulated sales
activity, combined to increase other expenses in 1999, compared to the
previous year.
Depreciation and amortization was reduced by $9.8 million in the
second half of 2000, following approval by the Public Utilities Commission
of Ohio (PUCO) of the Ohio transition plan (see Outlook). Total
accelerated cost recovery in connection with OE's rate reduction plan and
Penn's restructuring plan are summarized by income statement caption in
the table below:
Regulatory Plan Accelerations 2000 1999 1998
- ----------------------------------------------------------------
(In millions)
Depreciation and amortization $332.6 $333.3 $172.9
Income tax amortization 42.6 18.7 18.5
- -----------------------------------------------------------------
Total Accelerations $375.2 $352.0 $191.4
=================================================================
The impact of OE's rate reduction plan and Penn's restructuring plan on
depreciation and amortization was relatively unchanged in 2000 from 1999.
In 1999, accelerated cost recovery in connection with the OE rate
reduction plan was the primary factor contributing to the increase in
depreciation and amortization, compared to 1998.
Net Interest Charges
We continue to redeem and refinance our outstanding debt and
preferred stock, thus maintaining the downward trend in our financing
costs during 2000. Interest charges decreased by $43.2 million in 2000 and
$28.7 million in 1999, compared to the prior year. Net redemptions of
long-term debt and preferred stock totaled $405.9 million and refinancings
totaled $284.7 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 OE's generation business and the nonnuclear
generation businesses of CEI and TE effective with the PUCO approval of
the Ohio transition plan. Beginning June 30, 2000, the balance sheets of
our Ohio EUOC reflected that discontinuance with $1.6 billion of impaired
generating plant investment recognized as regulatory assets which will be
recovered as transition costs. We expect the incremental amortization of
transition costs in 2001 for the Ohio EUOC to be lower than the
depreciation and amortization accelerated under OE's former regulatory
plan in 2000. The application of SFAS 71 to CEI's and TE's nuclear
operations was discontinued in connection with the implementation of their
regulatory plan in 1997.
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, or $.13 per FirstEnergy common share.
The EUOC 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 they continue the
application of SFAS 71 to those operations.
Capital Resources and Liquidity
- -------------------------------
We continued to pursue cost efficiencies to fund strategic
investments while also strengthening our financial position in 2000. Net
security redemptions and refinancings in 2000 should generate annual
financing cost savings of about $33 million. Also, approval by the PUCO of
our transition plan on July 19, 2000 (see Outlook), was cited as an
important reason that Moody's Investors Service and Fitch upgraded our
EUOC debt ratings during the second half of 2000. Moody's ratings for
senior secured debt of OE and Penn were raised from Baa2 to Baa1, and for
CEI and TE from Ba1 to Baa3. Fitch's rating for senior secured debt of OE
was raised from BBB to BBB+ (Penn's remained at BBB+) and for CEI and TE
from BB+ to BBB-. Ratings of many of the junior securities of the EUOC
were upgraded to conform to rating relationships typical of investment
grade issuers. Those improved ratings should help to enhance our
opportunities for further savings in the future. As of December 31, 2000,
our common equity as a percentage of capitalization increased to nearly
42% from 38% at the end of 1998.
We had approximately $49.3 million of cash and temporary
investments and $699.8 million of short-term indebtedness on December 31,
2000. Our unused borrowing capability included $242.5 million under
revolving lines of credit. At the end of 2000, the EUOC had the capability
to issue $2.7 billion of additional first mortgage bonds on the basis of
property additions and retired bonds. Based upon applicable earnings
coverage tests and their respective charters, OE, Penn and TE could issue
$2.3 billion of preferred stock (assuming no additional debt was issued).
CEI has no restrictions on the issuance of preferred stock.
Our cash requirements in 2001 for operating expenses,
construction expenditures, scheduled debt maturities, preferred stock
redemptions and common stock repurchases are expected to be met without
increasing our net debt and preferred stock outstanding. However, our
anticipated merger with GPU (see Proposed Business Combination) is
expected to require the issuance of approximately $2.2 billion of
acquisition-related debt. During 2000, we reduced our total debt by
approximately $250.3 million. We have cash requirements of approximately
$2.6 billion for the 2001-2005 period to meet scheduled maturities of
long-term debt and sinking fund requirements of preferred stock (before
giving effect to the GPU acquisition). Of that amount, approximately
$193 million applies to 2001. During 2000, we repurchased and retired
7.9 million shares of our common stock at an average price of $24.51 per
share. As of December 31, 2000, we had repurchased 12.5 million of the
15 million shares authorized by our Board of Directors under the
three-year program, which began in March 1999.
Our capital spending (before giving effect to the GPU
acquisition) for the period 2001-2005 is expected to be about $3.0 billion
(excluding nuclear fuel), of which approximately $683 million applies to
2001. Capital spending in 2001 includes expenditures to complete five
combustion turbines expected to provide 425 megawatts (MW) of additional
peaking generation capacity to our system by mid-year 2001. Investments
for additional nuclear fuel during the 2001-2005 period are estimated to
be approximately $380 million, of which about $54 million applies to 2001.
During the same period, our nuclear fuel investments are expected to be
reduced by approximately $460 million and $100 million, respectively, as
the nuclear fuel is consumed. Also, we have operating lease commitments,
net of trust cash receipts, of nearly $821 million for the 2001-2005
period, of which approximately $161 million relates to 2001.
We invested $4.4 million in 2000 by joining with 20 other
leading energy and utility companies (including GPU) to form Pantellos
Corporation (Pantellos). Pantellos manages an online, independent
marketplace for buyers and sellers from the $130 billion North American
utility and energy supply market, which opened for business on January 1,
2001. We expect to realize savings by using the e-market site and to
benefit from our ownership interest in this new venture.
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 3, our investments in capital trusts effectively reduce
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.
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 $ 87 $ 84 $ 97 $314 $ 58 $1,402 $2,042 $2,086
Average interest rate 5.1% 7.7% 7.7% 7.8% 7.9% 7.4% 7.4%
- -------------------------------------------------------------------------------------------------
==================================================================================================
Liabilities
- -------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $106 $721 $460 $591 $436 $2,460 $4,774 $4,932
Average interest rate 8.6% 7.9% 8.0% 7.7% 8.8% 7.3% 7.7%
Variable rate $ 1 $101 $ 1 $ 1 $ 975 $1,079 $1,078
Average interest rate 8.2% 7.4% 8.0% 8.7% 4.8% 5.1%
Short-term Borrowings $700 $ 700 $ 700
Average interest rate 7.9% 7.9%
- -------------------------------------------------------------------------------------------------
Preferred Stock $ 85 $ 20 $ 2 $ 2 $ 2 $ 135 $ 246 $ 243
Average dividend rate 8.9% 8.9% 7.5% 7.5% 7.5% 8.8% 8.8%
==================================================================================================
Market Risk - Commodity Prices
- ------------------------------
We are exposed to market risk due to fluctuations in
electricity, natural gas, coal and oil prices. To manage the volatility
relating to these exposures, we use a variety of derivative instruments,
including forward contracts, options, futures contracts and swaps. These
derivatives are used principally for hedging purposes and, to a much
lesser extent, for trading purposes. We performed a sensitivity analysis
to estimate our exposure to the market risk of our commodity position. A
hypothetical 10% adverse shift in quoted market prices in the near term on
both our trading and nontrading instruments would not have had a material
effect on our consolidated financial position, results of operations or
cash flows as of or for the year ended December 31, 2000.
Outlook
- -------
On July 19, 2000, the PUCO approved our plan for transition to
customer choice in Ohio (see Note 1). As part of its authorization, the
PUCO approved a settlement agreement between us and major groups
representing most of our Ohio customers regarding the transition to
customer choice in selection of electricity suppliers. On January 1, 2001,
electric choice became available to our Ohio customers. Under the plan,
OE, CEI and TE continue to deliver power to homes and businesses through
their existing distribution systems, which remain regulated. Their 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, the regulated utility company reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component
plus an incentive, and the customer receives a generation charge from the
alternative supplier.
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
$500 million of transition revenue if the rate of customers (excluding
contracts and full-service accounts) switching their service from OE, CEI
and TE 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
are also committed under the transition agreement to make available
1,120 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 areas. Through February 8, 2001, approximately 794 MW of the
1,120 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 our Ohio EUOC had
been notified that about 108,000 of their customers requested generation
services from other authorized suppliers, including FirstEnergy Services
Corp. (FE Services), a wholly owned subsidiary.
Beginning in 2001, Ohio utilities that 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 our
regionally-focused retail sales strategy envisions the continued operation
of both regulated and competitive operations, our transition plan included
details for our corporate separation. The approved plan is consistent with
the way we managed our 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 the EUOC
continue to provide regulated transmission and distribution services.
FirstEnergy Generation Corp. (FE Generation), a wholly owned subsidiary of
FE Services, leases fossil and hydroelectric plants from the EUOC and
operates those plants. We expect that the transfer of ownership of the
EUOC fossil and hydroelectric generating assets to FE Generation will be
completed by the end of the market development period. All of the EUOC
power supply requirements are provided by FE Services to satisfy the EUOC
"provider of last resort" obligation under the transition plan, as well as
grandfathered wholesale contracts. The reportable segments in 2000 under
SFAS 131, "Disclosures about Segments of an Enterprise and Related
Information," reflect the management of these businesses as "Regulated
Services" and "Competitive Services." The "Corporate Support Services" is
included in "Other."
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. We believe the Sammis
Plant is in full compliance with the Clean Air Act and the legal actions
are without merit. We are unable, however, 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 Environmental Protection Agency (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.
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 6). 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 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.
CEI and TE have been named as "potentially responsible parties"
(PRPs) at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of
1980. Allegations of disposal of hazardous substances at historical sites
and the liability involved are often unsubstantiated and subject to
dispute. Federal law provides that all PRPs for a particular site be held
liable on a joint and several basis. CEI and TE have accrued liabilities
totaling $3.7 million as of December 31, 2000, based on estimates of the
total costs of cleanup, the proportionate responsibility of other PRPs for
such costs, and the financial ability of other PRPs to pay. CEI and TE
believe that waste disposal costs will not have a material adverse effect
on their financial condition, cash flows or results of operations.
Recently Issued Accounting Standards
- ------------------------------------
SFAS 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recognized on the balance
sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative instrument's fair value
be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative instrument's gains and losses to partially or wholly offset
related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
We adopted SFAS 133, as amended, on January 1, 2001. Prior to
adoption, we reviewed all outstanding contracts to determine if they were
derivatives or contained embedded derivatives. Derivatives involved in
"normal-purchase/normal-sale" transactions were documented and excluded
from further treatment under SFAS 133. The remaining derivatives were
either documented as cash flow hedges or treated as non-hedge derivatives.
In January 2001, we recorded assets and liabilities representing
the difference between the derivatives' previous carrying amounts and
their fair values under SFAS 133. Related amounts were recorded in net
income and comprehensive income. For derivatives that had previously been
treated as hedges of forecast transactions, the difference between the
derivatives' previous carrying amount and their fair value under SFAS 133
was an adjustment of accumulated other comprehensive income. For
derivatives not previously designated as hedges, the difference was an
adjustment to net income. These amounts will be reported separately in
results for the first quarter of 2001 as a "cumulative effect of a change
in accounting principle". The cumulative effect increases assets by
$108.3 million, liabilities by $72.6 million and common stockholders'
equity by $35.7 million -- other comprehensive income increases by
$44.2 million and net income is reduced by $8.5 million.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
REVENUES:
Electric utilities $5,421,668 $5,453,763 $5,237,468
Unregulated businesses 1,607,293 865,884 637,438
---------- ---------- ----------
Total revenues 7,028,961 6,319,647 5,874,906
---------- ---------- ----------
EXPENSES:
Fuel and purchased power 801,292 876,986 983,735
Other expenses:
Electric utilities 1,659,246 1,632,638 1,492,461
Unregulated businesses 1,582,151 792,576 742,778
Provision for depreciation and amortization 933,684 937,976 758,865
General taxes 547,681 544,052 550,908
---------- ---------- ----------
Total expenses 5,524,054 4,784,228 4,528,747
---------- ---------- ----------
INCOME BEFORE INTEREST AND INCOME TAXES 1,504,907 1,535,419 1,346,159
---------- ---------- ----------
NET INTEREST CHARGES:
Interest expense 493,473 509,169 542,819
Allowance for borrowed funds used during
construction and capitalized interest (27,059) (13,355) (7,642)
Subsidiaries' preferred stock dividends 62,721 76,479 65,799
---------- ---------- ----------
Net interest charges 529,135 572,293 600,976
---------- ---------- ----------
INCOME TAXES 376,802 394,827 303,787
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 598,970 568,299 441,396
EXTRAORDINARY ITEM (NET OF INCOME TAX BENEFIT OF
$21,208,000) (Note 1) -- -- (30,522)
---------- ---------- ----------
NET INCOME $ 598,970 $ 568,299 $ 410,874
========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 222,444 227,227 226,373
======= ======= =======
BASIC AND DILUTED EARNINGS PER SHARE OF
COMMON STOCK (Note 4C):
Income before extraordinary item $2.69 $2.50 $1.95
Extraordinary item (Net of income taxes) (Note 1) -- -- (.13)
----- ----- -----
Net income $2.69 $2.50 $1.82
===== ===== =====
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $1.50 $1.50 $1.50
===== ===== =====
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999
- -----------------------------------------------------------------------------------------------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 49,258 $ 111,788
Receivables-
Customers (less accumulated provisions of $15,800,000
and $6,719,000, respectively, for uncollectible accounts) 399,242 322,687
Other (less accumulated provisions of $20,486,000 and
$5,359,000, respectively, for uncollectible accounts) 519,207 445,242
Materials and supplies, at average cost--
Owned 171,563 154,834
Under consignment 112,155 99,231
Prepayments and other 189,869 167,894
----------- -----------
1,441,294 1,301,676
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service 12,417,684 14,645,131
Less--Accumulated provision for depreciation 5,263,483 5,919,170
----------- -----------
7,154,201 8,725,961
Construction work in progress 420,875 367,380
----------- -----------
7,575,076 9,093,341
----------- -----------
INVESTMENTS:
Capital trust investments (Note 3) 1,223,794 1,281,834
Nuclear plant decommissioning trusts 584,288 543,694
Letter of credit collateralization (Note 3) 277,763 277,763
Other 669,057 599,443
---------- ------------
2,754,902 2,702,734
----------- ------------
DEFERRED CHARGES:
Regulatory assets 3,727,662 2,543,427
Goodwill 2,088,770 2,129,902
Other 353,590 452,967
----------- -----------
6,170,022 5,126,296
----------- -----------
$17,941,294 $18,224,047
=========== ===========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock $ 536,482 $ 762,520
Short-term borrowings (Note 5) 699,765 417,819
Accounts payable 478,661 360,379
Accrued taxes 409,640 409,724
Accrued interest 116,544 125,397
Other 352,713 301,572
----------- -----------
2,593,805 2,377,411
----------- -----------
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders' equity 4,653,126 4,563,890
Preferred stock of consolidated subsidiaries--
Not subject to mandatory redemption 648,395 648,395
Subject to mandatory redemption 41,105 136,246
Ohio Edison obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely Ohio Edison
subordinated debentures 120,000 120,000
Long-term debt 5,742,048 6,001,264
----------- -----------
11,204,674 11,469,795
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes 2,094,107 2,231,265
Accumulated deferred investment tax credits 241,005 269,083
Nuclear plant decommissioning costs 598,985 562,295
Other postretirement benefits 544,541 498,184
Other 664,177 816,014
----------- -----------
4,142,815 4,376,841
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 3 and 6) ----------- -----------
$17,941,294 $18,224,047
=========== ===========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these balance sheets.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $.10 par value - authorized 375,000,000 shares
224,531,580 and 232,454,287 shares outstanding, respectively $ 22,453 $ 23,245
Other paid-in capital 3,531,821 3,722,375
Accumulated other comprehensive income (loss)(Note 4H) 593 (195)
Retained earnings (Note 4A) 1,209,991 945,241
Unallocated employee stock ownership plan common stock-
5,952,032 and 6,778,905 shares, respectively (Note 4B) (111,732) (126,776)
----------- -----------
Total common stockholders' equity 4,653,126 4,563,890
----------- -----------
Number of Shares Optional
Outstanding Redemption Price
---------------- ---------------------
2000 1999 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Note 4D):
Ohio Edison Company (OE)
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 4E):
8.45% 50,000 100,000 5,000 10,000
Redemption Within One Year (5,000) (5,000)
--------- --------- ----------- -----------
50,000 100,000 -- 5,000
========= ========= ----------- -----------
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:
7.625% 150,000 150,000 105.34 $ 15,801 15,000 15,000
========= ========= ======== ----------- -----------
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
2000 1999 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Cont'd)
Cleveland Electric Illuminating Company
Cumulative, without par value-
Authorized 4,000,000 shares
Not Subject to Mandatory Redemption:
$ 7.40 Series A 500,000 500,000 $ 101.00 $ 50,500 $ 50,000 $ 50,000
$ 7.56 Series B 450,000 450,000 102.26 46,017 45,071 45,071
Adjustable Series L 474,000 474,000 100.00 47,400 46,404 46,404
$42.40 Series T 200,000 200,000 500.00 100,000 96,850 96,850
--------- --------- -------- ----------- -----------
Total Not Subject to Mandatory
Redemption 1,624,000 1,624,000 $243,917 238,325 238,325
========= ========= ======== ----------- -----------
Subject to Mandatory Redemption:
$ 7.35 Series C 80,000 90,000 101.00 $ 8,080 8,041 9,110
$88.00 Series E -- 3,000 -- -- -- 3,000
$91.50 Series Q 10,716 21,430 1,000.00 10,716 10,716 21,430
$88.00 Series R 50,000 50,000 -- -- 51,128 55,000
$90.00 Series S 36,500 55,250 -- -- 36,686 61,170
--------- --------- -------- ----------- -----------
177,216 219,680 18,796 106,571 149,710
Redemption Within One Year (80,466) (33,464)
--------- --------- -------- ----------- -----------
Total Subject to Mandatory Redemption 177,216 219,680 $ 18,796 26,105 116,246
========= ========= ======== ----------- -----------
Toledo Edison Company
Cumulative, $100 par value-
Authorized 3,000,000 shares
Not Subject to Mandatory Redemption:
$ 4.25 160,000 160,000 104.63 $ 16,740 16,000 16,000
$ 4.56 50,000 50,000 101.00 5,050 5,000 5,000
$ 4.25 100,000 100,000 102.00 10,200 10,000 10,000
$ 8.32 100,000 100,000 102.46 10,246 10,000 10,000
$ 7.76 150,000 150,000 102.44 15,366 15,000 15,000
$ 7.80 150,000 150,000 101.65 15,248 15,000 15,000
$10.00 190,000 190,000 101.00 19,190 19,000 19,000
--------- --------- -------- ----------- -----------
900,000 900,000 92,040 90,000 90,000
--------- --------- -------- ----------- -----------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$2.21 1,000,000 1,000,000 25.25 25,250 25,000 25,000
$2.365 1,400,000 1,400,000 27.75 38,850 35,000 35,000
Adjustable Series A 1,200,000 1,200,000 25.00 30,000 30,000 30,000
Adjustable Series B 1,200,000 1,200,000 25.00 30,000 30,000 30,000
--------- --------- -------- ----------- -----------
4,800,000 4,800,000 124,100 120,000 120,000
--------- --------- -------- ----------- -----------
Total Not Subject to Mandatory
Redemption 5,700,000 5,700,000 $216,140 210,000 210,000
========= ========= ======== ----------- -----------
OE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY OE SUBORDINATED
DEBENTURES (Note 4F):
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
========= ========= ----------- -----------
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (Note 4G) (Interest rates reflect weighted average rates) (In thousands)
- --------------------------------------------------------------------------------------------------------------------------------
FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL
- --------------------------------------------------------------------------------------------------------------------------------
As of December 31, 2000 1999 2000 1999 2000 1999 2000 1999
---- ---- ---- ---- ---- ---- ---- ----
Ohio Edison Co. -
Due 2000-2005 7.89% $ 509,265 $ 589,265 7.53% $ 232,691 $ 316,623 5.75% $541,725 $ 742,225
Due 2006-2010 -- -- -- 7.74% 7,483 2,062 -- -- --
Due 2011-2015 -- -- -- 6.17% 59,000 40,000 -- -- --
Due 2016-2020 -- -- -- 7.05% 60,000 86,000 -- -- --
Due 2021-2025 7.99% 219,460 219,460 7.00% 69,943 69,943 -- -- --
Due 2026-2030 -- -- -- 5.48% 180,134 119,734 -- -- --
Due 2031-2035 -- -- -- 5.09% 71,900 14,800 -- -- --
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Total-Ohio Edison 728,725 808,725 681,151 649,162 541,725 742,225 $ 1,951,601 $ 2,200,112
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Cleveland Electric
Illuminating Co. -
Due 2000-2005 8.53% 595,000 595,000 7.85% 384,650 559,680 5.58% 27,700 27,700
Due 2006-2010 6.86% 125,000 125,000 7.29% 271,670 271,670 -- -- --
Due 2011-2015 -- -- -- 6.87% 118,535 118,535 -- -- --
Due 2016-2020 -- -- -- 6.88% 553,355 553,355 -- -- --
Due 2021-2025 9.00% 150,000 150,000 7.70% 226,450 226,450 -- -- --
Due 2026-2030 -- -- -- 4.80% 110,888 110,888 -- -- --
Due 2031-2035 -- -- -- -- -- -- -- -- --
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Total-Cleveland
Electric 870,000 870,000 1,665,548 1,840,578 27,700 27,700 2,563,248 2,738,278
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Toledo Edison Co. -
Due 2000-2005 7.90% 179,525 179,925 8.06% 190,400 266,000 7.28% 226,100 226,130
Due 2006-2010 -- -- -- 7.13% 30,000 30,000 10.00% 820 820
Due 2011-2015 -- -- -- -- -- -- -- -- --
Due 2016-2020 -- -- -- 7.69% 99,000 166,300 -- -- --
Due 2021-2025 -- -- -- 7.39% 148,000 111,600 -- -- --
Due 2026-2030 -- -- -- 5.90% 13,851 13,851 -- -- --
Due 2031-2035 -- -- -- 5.15% 30,900 -- -- -- --
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Total-Toledo Edison 179,525 179,925 512,151 587,751 226,920 226,950 918,596 994,626
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Pennsylvania Power Co. -
Due 2000-2005 7.19% 79,370 80,344 -- -- 28,200 5.90% 5,200 5,200
Due 2006-2010 9.74% 4,870 4,870 -- -- -- -- -- --
Due 2011-2015 9.74% 4,870 4,870 5.40% 1,000 1,000 -- -- --
Due 2016-2020 9.74% 3,929 3,929 6.28% 45,325 45,325 -- -- --
Due 2021-2025 8.33% 33,750 33,750 6.68% 27,182 27,182 -- -- --
Due 2026-2030 -- -- -- 6.10% 47,972 47,972 -- -- --
Due 2031-2035 -- -- -- -- -- -- -- -- --
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
Total-Penn Power 126,789 127,763 121,479 149,679 5,200 5,200 253,468 282,642
---------- ---------- ---------- ---------- -------- ---------- ----------- -----------
OES Fuel -- -- 7.10% 91,620 81,260 -- -- -- 91,620 81,260
Bay Shore Power -- -- 6.60% 147,500 147,500 -- -- -- 147,500 147,500
MARBEL Energy Corp. -- -- -- -- -- 9.37% 638 692 638 692
Facilities Services
Group -- -- 6.53% 17,601 14,782 7.29% -- 1,887 17,601 16,669
---------- ---------- ---------- ---------- -------- --------- ----------- -----------
Total $1,905,039 $1,986,413 $3,237,050 $3,470,712 $802,183 $1,004,654 5,944,272 6,461,779
========== ========== ========== ========== ======== ========== ----------- -----------
Capital lease
obligations 163,242 158,303
----------- -----------
Net unamortized premium on debt 85,550 105,238
----------- -----------
Long-term debt due within one year (451,016) (724,056)
----------- -----------
Total long-term debt 5,742,048 6,001,264
----------- -----------
TOTAL CAPITALIZATION $11,204,674 $11,469,795
- --------------------------------------------------------------------------------------------------------------------------------
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Accumulated Unallocated
Other Other ESOP
Comprehensive Number Par Paid-In Comprehensive Retained Common
Income of Shares Value Capital Income (Loss) Earnings Stock
------------- --------- ----- ------- ------------- -------- -----------
(Dollars in thousands)
Balance, January 1, 1998 230,207,141 $23,021 $3,637,522 $(614) $ 646,646 $(146,977)
Net income $410,874 410,874
Minimum liability for unfunded
retirement benefits, net of
$53,000 of income taxes 175 175
--------
Comprehensive income $411,049
========
Business acquisitions 6,861,946 686 203,496
Allocation of ESOP Shares 5,495 7,945
Cash dividends on common stock (339,111)
- -----------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 237,069,087 23,707 3,846,513 (439) 718,409 (139,032)
Net income $568,299 568,299
Minimum liability for unfunded
retirement benefits, net of
$160,000 of income taxes 244 244
--------
Comprehensive income $568,543
========
Reacquired common stock (4,614,800) (462) (129,671)
Centerior acquisition adjustment (468)
Allocation of ESOP Shares 6,001 12,256
Cash dividends on common stock (341,467)
- ----------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 232,454,287 23,245 3,722,375 (195) 945,241 (126,776)
Net income $598,970 598,970
Minimum liability for unfunded
retirement benefits, net of
$(85,000) of income taxes (134) (134)
Unrealized gain on investment of
securities available for sale 922 922
--------
Comprehensive income $599,758
========
Reacquired common stock (7,922,707) (792) (194,210)
Allocation of ESOP Shares 3,656 15,044
Cash dividends on common stock (334,220)
- ----------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 224,531,580 $22,453 $3,531,821 $ 593 $1,209,991 $(111,732)
==============================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- -------------------
Par or Par or
Number Stated Number Stated
of Shares Value of Shares Value
--------- ------ --------- ------
(Dollars in thousands)
- -------------------------------------------------------------------------------------------
Balance, January 1, 1998 12,442,699 $660,195 5,469,408 $356,243
Redemptions-
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$9.375 Series (16,650) (1,665)
- -------------------------------------------------------------------------------------------
Balance, December 31, 1998 12,442,699 660,195 5,379,044 334,864
Redemptions-
7.64% Series (60,000) (6,000)
8.00% Series (58,000) (5,800)
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$90.00 Series S (18,750) (18,750)
$9.375 Series (16,900) (1,690)
- -------------------------------------------------------------------------------------------
Balance, December 31, 1999 12,324,699 648,395 5,269,680 294,710
Redemptions-
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$90.00 Series S (18,750) (18,750)
Amortization of fair market
value adjustments-
$ 7.35 Series C (69)
$88.00 Series R (3,872)
$90.00 Series S (5,734)
- -------------------------------------------------------------------------------------------
Balance, December 31, 2000 12,324,699 $648,395 5,177,216 $246,571
============================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 598,970 $ 568,299 $ 410,874
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 933,684 937,976 758,865
Nuclear fuel and lease amortization 113,330 104,928 94,348
Other amortization, net (11,635) (10,730) (13,007)
Deferred income taxes, net (79,429) (45,054) (23,763)
Investment tax credits, net (30,732) (19,661) (22,070)
Extraordinary item -- -- 51,730
Receivables (150,520) (203,567) 35,515
Materials and supplies (29,653) 19,631 (14,235)
Accounts payable 118,282 82,578 (73,205)
Other 45,529 53,906 (49,727)
---------- ---------- ----------
Net cash provided from operating activities 1,507,826 1,488,306 1,155,325
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Common stock -- -- 204,182
Long-term debt 307,512 364,832 499,975
Ohio Schools Council prepayment program -- -- 116,598
Short-term borrowings, net 281,946 163,327 --
Redemptions and Repayments-
Common stock 195,002 130,133 --
Preferred stock 38,464 52,159 21,379
Long-term debt 901,764 847,006 804,780
Short-term borrowings, net -- -- 48,354
Common Stock Dividend Payments 334,220 341,467 339,111
---------- ---------- ----------
Net cash used for financing activities 879,992 842,606 392,869
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 587,618 624,901 652,852
Cash investments (17,449) (41,213) 47,804
Other 120,195 28,022 82,239
---------- ---------- ----------
Net cash used for investing activities 690,364 611,710 782,895
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents (62,530) 33,990 (20,439)
Cash and cash equivalents at beginning of year 111,788 77,798 98,237
---------- ---------- ----------
Cash and cash equivalents at end of year $ 49,258 $ 111,788 $ 77,798
========== ========== ==========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $ 485,374 $ 520,072 $ 536,064
Income taxes $ 512,182 $ 441,067 $ 326,268
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2000 1999 1998
- --------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 281,374 $ 276,227 $ 292,503
State gross receipts 221,385 220,117 217,633
Social security and unemployment 39,134 37,019 27,363
Other 5,788 10,689 13,409
---------- ---------- ----------
Total general taxes $ 547,681 $ 544,052 $ 550,908
========== ========== ==========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 467,045 $ 433,872 $ 313,960
State 19,918 25,670 14,452
---------- ---------- ----------
486,963 459,542 328,412
---------- ---------- ----------
Deferred, net-
Federal (60,831) (36,021) (14,259)
State (18,598) (9,033) (9,504)
---------- ---------- ----------
(79,429) (45,054) (23,763)
---------- ---------- ----------
Investment tax credit amortization (30,732) (19,661) (22,070)
---------- ---------- ----------
Total provision for income taxes $ 376,802 $ 394,827 $ 282,579
========== ========== ==========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 975,772 $ 963,126 $ 693,453
========== ========== ==========
Federal income tax expense at statutory rate $ 341,520 $ 337,094 $ 242,709
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (30,732) (19,661) (22,070)
State income taxes, net of federal income tax benefit 1,133 10,814 3,216
Amortization of tax regulatory assets 38,702 23,908 28,915
Amortization of goodwill 18,420 19,341 17,868
Preferred stock dividends 18,172 22,988 19,250
Other, net (10,413) 343 (7,309)
---------- ---------- ----------
Total provision for income taxes $ 376,802 $ 394,827 $ 282,579
========== ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences $1,245,297 $1,878,904 $1,938,735
Deferred nuclear expense 408,771 421,837 436,601
Impaired generating assets 565,893 -- --
Customer receivables for future income taxes 62,527 159,577 159,526
Competitive transition charge 95,497 115,277 135,730
Deferred sale and leaseback costs (128,298) (129,775) (61,506)
Unamortized investment tax credits (85,641) (96,036) (102,085)
Unused alternative minimum tax credits (32,215) (101,185) (190,781)
Other (37,724) (17,334) (33,356)
---------- ---------- ----------
Net deferred income tax liability $2,094,107 $2,231,265 $2,282,864
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include FirstEnergy Corp.
(Company) and its principal electric utility operating subsidiaries, Ohio
Edison Company (OE), The Cleveland Electric Illuminating Company (CEI),
Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE).
These utility subsidiaries are referred to throughout as "Companies." On
September 1, 2000, the Companies transferred their transmission assets to
the Company's wholly owned subsidiary, American Transmission Systems, Inc.
(ATSI). As a result, ATSI owns and operates the Company's major
high-voltage transmission facilities and has interconnections with other
regional utilities. The consolidated financial statements also include the
Company's other principal subsidiaries: FirstEnergy Services Corp. (FE
Services); FirstEnergy Facilities Services Group, LLC (FE Facilities);
FirstEnergy Trading Services, Inc. (FETS), which merged into FE Services
on January 1, 2001; and MARBEL Energy Corporation (MARBEL). FE Services
provides energy-related products and services primarily on a regional
basis and has two subsidiaries, Penn Power Energy, Inc., which provides
electric generation services and other energy services to Pennsylvania
customers and FirstEnergy Generation Corp., which operates the nonnuclear
generation businesses of the Companies. FE Facilities is the parent
company of several heating, ventilating, air conditioning and energy
management companies. FETS had primarily acquired and arranged for the
delivery of electricity and natural gas to FE Services' retail customers.
MARBEL is a fully integrated natural gas company. Significant intercompany
transactions have been eliminated.
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. Certain prior year amounts have been reclassified
to conform with the current year presentation.
REVENUES-
The Companies' principal business is providing electric service
to customers in central and northern 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.
CEI and TE sell substantially all of their retail customer
receivables to Centerior Funding Corp. (CFC), a wholly owned subsidiary of
CEI. CFC subsequently transfers the receivables to a trust under an asset-
backed securitization agreement. The trust completed a public sale of
$150 million and private sales of $50 million of receivables-backed
investor certificates in 1996 and 2000, respectively, in transactions that
qualified for sale accounting treatment. CFC's retained interest in the
pool of receivables held by the trust (15.15% as of December 31, 2000) is
stated at fair value, reflecting adjustments for anticipated credit
losses. Collections of receivables previously transferred to the trust
used to purchase new receivables from CFC during 2000, totaled
approximately $2.5 billion. Expenses associated with the factoring
discount related to the sale of receivables were $13 million in 2000. As
of December 31, 2000, receivables recorded on the Consolidated Balance
Sheet were reduced by $193 million due to these sales.
REGULATORY PLANS-
The PUCO approved OE's Rate Reduction and Economic Development
Plan in 1995 and FirstEnergy's Rate Reduction and Economic Development
Plan for CEI and TE in January 1997. These regulatory plans were to
maintain then current base electric rates for OE, CEI and TE through
December 31, 2005. At the end of the regulatory plan periods, OE base
rates were to be reduced by $300 million (approximately 20 percent below
then current levels) and CEI and TE base rates were to be reduced by a
combined $310 million (approximately 15 percent below then current
levels). The plans also revised the Companies' fuel cost recovery methods
so that OE's, CEI's and TE's fuel rates would be frozen through the
regulatory plan period, subject to limited periodic adjustments. As part
of OE's and FirstEnergy's regulatory plans, transition rate credits were
implemented for customers, which were expected to reduce operating
revenues for OE by approximately $600 million and CEI and TE by
approximately $391 million during the regulatory plan period. The
regulatory plans were 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.
The Company, on behalf of its Ohio electric utility operating
companies -- OE, 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, the Company'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 the Company'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 generation-related transition costs of approximately
$4.5 billion ($4.0 billion, net of deferred income taxes) and transition
costs related to regulatory assets aggregating approximately $4.2 billion
($2.9 billion, net of deferred income taxes).
On July 19, 2000, the PUCO approved the Company'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 OE, mid-2007 for TE and 2008
for CEI, except where a longer period of recovery is provided for in the
settlement agreement. The Company will also give preferred access over the
Company's subsidiaries to nonaffiliated marketers, brokers and aggregators
to 1,120 megawatts of generation capacity through 2005 at established prices
for sales to the Ohio operating companies' retail customers. The base
electric rates for distribution service for OE, CEI and TE under their prior
respective regulatory plans will be extended from December 31, 2005 through
December 31, 2007. The transition rate credits for customers under their
prior regulatory plans will also be extended through the Companies'
respective transition cost recovery periods.
The application of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71), to OE's generation business and the nonnuclear generation
businesses of CEI and TE 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 $1.6 billion of impaired plant investments ($1.2 billion,
$304 million and $53 million for OE, CEI and TE, respectively) were
recognized as regulatory assets recoverable as transition costs through
future regulatory cash flows.
The settlement agreement provides to the Company's Ohio 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 1,120 megawatts
described in a previous paragraph). 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 periods. If the customer switching targets established in the
settlement agreement are not achieved by the end of 2005, the transition
cost recovery periods could be shortened for OE, CEI and TE to reduce
recovery by as much as $500 million (OE-$250 million, CEI-$170 million and
TE-$80 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.
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 OE 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, OE's and Penn's cumulative
additional capital recovery and regulatory asset amortization amounted to
$1.424 billion (including Penn's impairment discussed above and CTC
recovery). CEI and TE recognized a fair value purchase accounting
adjustment of $2.55 billion in connection with the FirstEnergy merger;
that fair value adjustment recognized for financial reporting purposes
satisfied the $2 billion asset reduction commitment contained in the CEI
and TE regulatory plan. For regulatory purposes, CEI and TE recognized the
accelerated amortization over the period that their rate plan was in
effect.
Application of SFAS 71 was discontinued in 1997 with respect to
CEI's and TE's nuclear operations (see "Regulatory Assets" below); in 1998
with respect to Penn's generation operations (as described above) and in
mid-2000, as discussed above, with respect to OE's generation business and
the nonnuclear generation businesses of CEI and TE effective with the
issuance of the PUCO transition plan order. The following summarizes net
assets included in property, plant and equipment relating to operations
for which the application of SFAS 71 was discontinued, compared with the
respective company's total assets as of December 31, 2000.
SFAS 71
Discontinued
Net Assets Total Assets
------------ ------------
(In millions)
OE $1,075 $7,422
CEI 1,556 5,965
TE 623 2,652
Penn 92 989
PROPERTY, PLANT AND EQUIPMENT-
Property, plant and equipment reflects original cost (except for
the Companies' nuclear generating units which were adjusted to fair
value), including payroll and related costs such as taxes, employee
benefits, administrative and general costs, and interest costs.
The Companies 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 OE'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. CEI's and TE's composite rates were both
approximately 3.4% in 2000, 1999 and 1998. In addition to the
straight-line depreciation recognized in 2000, 1999 and 1998, OE and Penn
recognized additional capital recovery of $105 million, $95 million and
$141 million (excluding Penn's impairment), respectively, as depreciation
expense in accordance with their regulatory plans. These amounts were
included in the 2000 transfer of accumulated depreciation included in OE's
impaired plant investment recognized as regulatory assets as discussed in
"Regulatory Plans" above.
Annual depreciation expense in 2000 included approximately
$29.3 million for future decommissioning costs applicable to the
Companies' ownership and leasehold interests in four nuclear generating
units. Annual decommissioning costs will increase by approximately
$66 million from implementing the Ohio utilities' transition plan in 2001.
The Companies' future decommissioning costs reflect the 1999 increase in
their ownership interests 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 $1.9 billion in
current dollars and (using a 4.0% escalation rate) approximately
$4.5 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
$342 million for decommissioning through their electric rates from
customers through December 31, 2000. The Companies have also recognized an
estimated liability of approximately $31.6 million related to
decontamination and decommissioning of nuclear enrichment facilities
operated by the United States Department of Energy (DOE), 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.
NUCLEAR FUEL-
OE's and Penn's nuclear fuel is recorded at original cost, which
includes material, enrichment, fabrication and interest costs incurred
prior to reactor load. CEI and TE severally lease their respective
portions of nuclear fuel and pay for the fuel as it is consumed (see
Note 3). 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. Alternative minimum tax
credits of $32 million, which may be carried forward indefinitely, are
available to reduce future federal income taxes.
RETIREMENT BENEFITS-
The Companies' trusteed, noncontributory defined benefit pension
plan covers almost all 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 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 the 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)
=====================================================================================
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%
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
==================================================================================================
The 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.
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 fair market value. Noncash
financing and investing activities included capital lease transactions
amounting to $89.3 million, $36.2 million and $61.8 million for the years
2000, 1999 and 1998, respectively. Commercial paper transactions of OES
Fuel, Incorporated (OES Fuel) (a wholly owned subsidiary of OE) 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 4G).
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 $5,853 $6,010 $6,381 $6,331
Preferred stock $ 247 $ 243 $ 295 $ 280
Investments other than cash
and cash equivalents:
Debt securities
?Maturity (5-10 years) $ 460 $ 441 $ 475 $ 476
?Maturity (more than
10 years) 1,026 1,051 1,068 1,013
Equity securities 16 16 17 17
All other 924 935 852 874
- -----------------------------------------------------------------------
$2,426 $2,443 $2,412 $2,380
=====================================================================
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 a corresponding change to the decommissioning liability. The
Companies have no securities held for trading purposes.
Effective December 31, 1998, the Company began accounting for
its commodity price derivatives, entered into specifically for trading
purposes, on a mark-to-market basis in accordance with Emerging Issues
Task Force Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities," with gains and losses recognized currently in the
Consolidated Statements of Income. The contracts that were marked to
market are included in the Consolidated Balance Sheets as Deferred Charges
and Deferred Credits at their fair values. The impact on the consolidated
financial statements was immaterial.
On January 1, 2001, the Company adopted SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities, as amended by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities -- an amendment of FASB Statement No. 133." The cumulative
effect of adopting SFAS 133, as amended, increases assets by
$108.3 million, liabilities by $72.6 million and common stockholders'
equity by $35.7 million -- other comprehensive income increases by
$44.2 million and net income is reduced by $8.5 million.
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. OE and
Penn 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 OE's generation business and the nonnuclear
generation businesses of CEI and TE was discontinued effective with the
PUCO's approval of the Company'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 $1.6 billion
($1.2 billion, $304 million and $53 million for OE, CEI and TE,
respectively).
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2000 1999
------------------------------------------------------------------
(In millions)
Nuclear unit expenses $1,081.1 $1,123.0
Customer receivables for future
income taxes 173.5 444.3
Rate stabilization program deferrals 400.0 420.1
Sale and leaseback costs 8.0 17.8
Competitive transition charge 230.9 280.4
Loss on reacquired debt 167.1 173.9
Employee postretirement benefit costs 20.7 24.8
DOE decommissioning and decontamination
costs 26.8 29.5
Impaired generating assets 1,595.5 --
Other 24.1 29.6
------------------------------------------------------------------
Total $3,727.7 $2,543.4
================================================================
2. MERGER AGREEMENT:
On August 8, 2000, FirstEnergy and GPU, Inc. (GPU), a
Pennsylvania corporation, entered into an Agreement and Plan of Merger.
Under the merger agreement, FirstEnergy would acquire all of the
outstanding shares of GPU's common stock for approximately $4.5 billion in
cash and FirstEnergy common stock. Approximately $7.4 billion of debt and
preferred stock of GPU's subsidiaries would remain outstanding. The
transaction would be accounted for by the purchase method. The combined
company's principal electric utility operating companies would include OE,
CEI, TE, Penn and ATSI, as well as GPU's electric utility operating
companies - Jersey Central Power & Light Company, Metropolitan Edison
Company and Pennsylvania Electric Company, which serve customers in New
Jersey and Pennsylvania.
Under the agreement, GPU shareholders would receive the
equivalent of $36.50 for each share of GPU common stock they own, payable
in cash or in FirstEnergy common stock, as long as FirstEnergy's common
stock price is between $24.2438 and $29.6313. Each GPU shareholder would
be able to elect the form of consideration they wish to receive, subject
to proration so that the aggregate consideration to all GPU shareholders
will be 50 percent cash and 50 percent FirstEnergy common stock. Each GPU
share converted into FirstEnergy common stock would receive not less than
1.2318 and not more than 1.5055 shares of FirstEnergy common stock,
depending on the average closing price of FirstEnergy stock during the
20-day trading period ending on the seventh trading date prior to the
merger closing. The stock portion of the consideration is expected to be
tax-free to GPU shareholders.
The merger has been approved by the respective shareholders of
the Company and GPU and is expected to close promptly after all of the
conditions to the consummation of the merger, including the receipt of all
necessary regulatory approvals, are fulfilled or waived. The receipt of
all necessary regulatory approvals, including, but not limited to, the
FERC, the Nuclear Regulatory Commission, the Federal Communications
Commission, and the SEC, are expected by the end of the second quarter of
2001.
3. LEASES:
The Companies lease certain generating facilities, nuclear fuel,
office space and other property and equipment under cancelable and
noncancelable leases.
OE sold portions of its ownership interests 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. CEI and TE also sold
portions of their ownership interests in Beaver Valley Unit 2 and Bruce
Mansfield Units 1, 2 and 3 and entered into similar operating leases for
lease terms of approximately 30 years. During the terms of their
respective leases, OE, CEI and TE continue to be responsible, to the
extent of their 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. They have the right, at the end of the
respective basic lease terms, to renew their respective leases. They also
have 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 OE, maintains deposits pledged as collateral to secure
reimbursement obligations relating to certain letters of credit supporting
OE'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 OE as sole owner of OES Finance common
stock.
Nuclear fuel is currently financed for CEI and TE through leases
with a special-purpose corporation. As of December 31, 2000, $142 million
of nuclear fuel was financed under a lease financing arrangement through
$150 million of bank credit arrangements. The bank credit arrangements
expire in August 2001. Lease rates are based on bank rates and commercial
paper rates.
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 $202.4 $208.6 $201.2
Other 111.1 110.3 147.8
Capital leases
Interest element 12.3 17.5 17.6
Other 64.2 76.1 66.3
---------------------------------------------------------
Total rentals $390.0 $412.5 $432.9
=======================================================
The future minimum lease payments as of December 31, 2000, are:
Operating Leases
----------------------------------
Capital Lease Capital
Leases Payments Trusts Net
- -------------------------------------------------------------------------
(In millions)
2001 $ 74.3 $ 306.8 $ 146.0 $ 160.8
2002 50.1 317.9 169.5 148.4
2003 32.9 326.1 176.5 149.6
2004 19.6 291.3 110.7 180.6
2005 9.6 310.1 128.8 181.3
Years thereafter 17.7 3,321.2 1,235.6 2,085.6
- -------------------------------------------------------------------------
Total minimum lease
payments 204.2 $4,873.4 $1,967.1 $2,906.3
Executory costs 10.6 ======== ======== ========
- ------------------------------------
Net minimum lease payments 193.6
Interest portion 30.4
- ------------------------------------
Present value of net
minimum lease payments 163.2
Less current portion 52.0
- ------------------------------------
Noncurrent portion $111.2
===================================
OE invested in the PNBV Capital Trust, which was established to
purchase a portion of the lease obligation bonds issued on behalf of
lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback
transactions. CEI and TE established the Shippingport Capital Trust to
purchase the lease obligation bonds issued on behalf of lessors in their
Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV
and Shippingport capital trust arrangements effectively reduce lease costs
related to those transactions.
4. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for payment of
cash dividends on the Company's common stock.
(B) EMPLOYEE STOCK OWNERSHIP PLAN-
The Companies fund the matching contribution for their 401(k)
savings plan through an ESOP Trust. All full-time employees eligible for
participation in the 401(k) savings plan are covered by the ESOP. The ESOP
borrowed $200 million from OE and acquired 10,654,114 shares of OE's
common stock (subsequently converted to FirstEnergy common stock) through
market purchases. 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. In 2000, 1999 and 1998, 826,873 shares, 627,427 shares
and 423,206 shares, respectively, were allocated to employees with the
corresponding expense recognized based on the shares allocated method. The
fair value of 5,952,032 shares unallocated as of December 31, 2000, was
approximately $187.8 million. Total ESOP-related compensation expense was
calculated as follows:
2000 1999 1998
- -----------------------------------------------------------------------
(In millions)
Base compensation $18.7 $18.3 $13.5
Dividends on common stock held by the ESOP
and used to service debt (6.4) (4.5) (3.9)
- ------------------------------------------------------------------------
Net expense $12.3 $13.8 $ 9.6
========================================================================
(C) STOCK COMPENSATION PLANS-
On April 30, 1998, the Company adopted the Executive and
Director Incentive Compensation Plan (FE Plan). The FE Plan permits awards
to be made to key employees in the form of restricted stock, stock
options, stock appreciation rights, performance shares or cash. Common
stock granted under the FE Plan may not exceed 7.5 million shares. No
stock appreciation rights or performance shares have been issued under the
FE Plan. Restricted common stock shares were granted under the FE Plan in
1998, 1999 and 2000 for various vesting periods ranging from six months to
eight years. The restricted common stock shares were purchased in the open
market and have full voting and dividend rights. There were no exercise
prices related to these shares. Restricted common stock grants were as
follows:
2000 1999 1998
- ----------------------------------------------------------------
Restricted common shares granted 208,400 8,000 20,000
Weighted average market price $26.63 $30.89 $30.78
Weighted average vesting period 3.8 5.8 4.0
Dividends restricted Yes Yes No
- ----------------------------------------------------------------
FE Plan options were granted in 1998, 1999 and 2000 and are
exercisable after four years from the date of grant with some acceleration
of vesting possible based on performance. Stock options, which were
granted prior to 1998, expire on or before February 25, 2007. Stock option
activity was as follows:
Number of Weighted Average
Stock Option Activity Options Exercise Price
- -------------------------------------------------------------------------
Balance at December 31, 1997 517,388 $24.59
(517,388 options exercisable)
Options granted 189,491 29.82
Options exercised 335,058 24.67
Options forfeited 7,535 29.82
Balance at December 31, 1998 364,286 27.13
(182,330 options exercisable)
Options granted 1,811,658 24.90
Options exercised 22,575 21.42
Balance at December 31, 1999 2,153,369 25.32
(159,755 options exercisable)
Options granted 3,011,584 23.24
Options exercised 90,491 26.00
Options forfeited 52,600 22.20
Balance at December 31, 2000 5,021,862 24.09
(473,314 options exercisable)
- -------------------------------------------------------------------------
As of December 31, 2000, the weighted average remaining
contractual life of outstanding stock options was 8.4 years.
Under the Executive Deferred Compensation Plan, adopted
January 1, 1999, employees can direct a portion of their Annual Incentive
Award and/or Long Term Incentive Award into an unfunded FirstEnergy Stock
Account to receive vested stock units. An additional 20% premium is
received in the form of stock units based on the amount allocated to the
FirstEnergy Stock Account. Dividends are calculated quarterly on stock
units outstanding and are paid in the form of additional stock units. Upon
withdrawal, stock units are converted to FirstEnergy shares. Payout occurs
three years from the date of deferral. As of December 31, 2000, there were
123,787.48 stock units outstanding.
The Company continues to apply Accounting Principles Board
Opinion 25, "Accounting for Stock Issued to Employees." As required by
SFAS 123, "Accounting for Stock-Based Compensation," the Company has
determined pro forma earnings as though the Company had accounted for
employee stock options under the fair value method. The weighted average
assumptions used in valuing the options and their resulting fair values
are as follows:
2000 1999 1998
- ---------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 7.6 6.4 10
Expected volatility 21.77% 20.03% 15.50%
Expected dividend yield 6.68% 5.97% 5.68%
Risk-free interest rate 5.28% 5.97% 5.65%
Fair value per option $2.86 $3.42 $3.25
- ---------------------------------------------------------------
The following table summarizes the pro forma effect of applying
fair value accounting to the Company's stock options.
2000 1999 1998
- ------------------------------------------------------------------
Net Income (000)
As Reported $598,970 $568,299 $410,874
Pro Forma $597,378 $567,876 $410,839
Earnings Per Share
of Common Stock -
Basic and Diluted
As Reported $2.69 $2.50 $1.82
Pro Forma $2.69 $2.50 $1.81
- -------------------------------------------------------------------
(D) PREFERRED AND PREFERENCE STOCK-
Penn's 7.75% series of preferred stock has a restriction which
prevents early redemption prior to July 2003. OE's 8.45% series of
preferred stock has no optional redemption provision. CEI's $88.00
Series R preferred stock is not redeemable before December 2001 and its
$90.00 Series S has no optional redemption provision. All other preferred
stock may be redeemed by the Companies in whole, or in part, with 30-90
days' notice.
Preference stock authorized for the Companies are 8 million
shares without par value for OE; 3 million shares without par value for
CEI; and 5 million shares, $25 par value for TE. No preference shares are
currently outstanding.
(E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions for the Companies' preferred
stock are as follows:
Redemption
Price Per
Series Shares Share Date Beginning
- --------------------------------------------------------------------------
OE 8.45% 50,000 $ 100 (i)
CEI $ 7.35 C 10,000 100 (i)
91.50 Q 10,714 1,000 (i)
90.00 S 18,750 1,000 (i)
88.00 R 50,000 1,000 December 1 2001
Penn 7.625% 7,500 100 October 1 2002
- --------------------------------------------------------------------------
<FN>
(i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are
$85 million in 2001, $19 million in 2002 and $2 million in each year
2003-2005.
(F) OHIO EDISON OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES
OF SUBSIDIARY TRUST HOLDING SOLELY OHIO EDISON SUBORDINATED
DEBENTURES-
Ohio Edison Financing Trust, a wholly owned subsidiary of OE,
has issued $120 million of 9% Cumulative Trust Preferred Capital
Securities. OE 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 OE 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. OE'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
OE of payments due on the Preferred Securities.
(G) 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, OE's, TE's and Penn's annual sinking and
improvement fund requirements for all bonds issued under the mortgage
amounts to $31.4 million. OE, TE and Penn 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 $399.0
2002 945.0
2003 460.1
2004 833.9
2005 436.3
--------------------------
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 $341.2 million and noncancelable
municipal bond insurance policies of $280 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 1.375% of the amounts of the letters of credit
to the issuing banks and are obligated to reimburse the banks for any
drawings thereunder.
OE 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. OE must pay an annual facility
fee of 0.20% on the total credit facility amount. In addition, the credit
agreement provides that OE maintain unused first mortgage bond capability
for the full credit agreement amount under OE's indenture as potential
security for the unsecured borrowings.
CEI and TE have letters of credit of approximately $222 million
in connection with the sale and leaseback of Beaver Valley Unit 2 that
expire in May 2002. The letters of credit are secured by first mortgage
bonds of CEI and TE in the proportion of 40% and 60%, respectively (see
Note 3).
OE's and Penn's 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.
(H) COMPREHENSIVE INCOME-
Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common
stockholders' equity except those resulting from transactions with common
stockholders. As of December 31, 2000, accumulated other comprehensive
income (loss) consisted of a minimum liability for unfunded retirement
benefits of $(329,000) and an unrealized gain on investment of securities
available for sale of $922,000.
5. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding as of December 31, 2000,
consisted of $539.8 million of bank borrowings and $159.9 million of OES
Capital, Incorporated (OES Capital) commercial paper. OES Capital is a
wholly owned subsidiary of OE 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.
The Companies have various credit facilities with domestic banks
that provide for borrowings of up to $505 million under various interest
rate options. OE's short-term borrowings may be made under its lines of
credit on its unsecured notes. To assure the availability of these lines,
the Companies are required to pay annual commitment fees that vary from
0.15% to 0.375%. 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 7.92% and 6.51%, respectively.
6. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $3.0 billion for property additions and improvements from
2001-2005, of which approximately $683 million is applicable to 2001.
Investments for additional nuclear fuel during the 2001-2005 period are
estimated to be approximately $380 million, of which approximately
$54 million applies to 2001. During the same periods, the Companies'
nuclear fuel investments are expected to be reduced by approximately
$460 million and $100 million, respectively, as the nuclear fuel is
consumed.
STOCK REPURCHASE PROGRAM-
On November 17, 1998, the Board of Directors authorized the
repurchase of up to 15 million shares of the Company's common stock over a
three-year period beginning in 1999. Repurchases are made on the open
market, at prevailing prices, and are funded primarily through the use of
operating cash flows. During 2000 and 1999, the Company repurchased and
retired 7.9 million shares (average price of $24.51 per share) and
4.6 million shares (average price of $28.08 per share), respectively.
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. The Companies' maximum potential assessment
under the industry retrospective rating plan would be $352.4 million per
incident but not more than $40 million in any one year for each incident.
The Companies are also insured under policies for each nuclear
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 $789 million of insurance coverage for
replacement power costs. Under these policies, the Companies can be
assessed a maximum of approximately $38 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. The Companies estimate additional capital expenditures for
environmental compliance of approximately $201 million, which is included
in the construction forecast provided under "Capital Expenditures" for
2001 through 2005.
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. The
Companies continue to evaluate their 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 OE and Penn 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 Company believes 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.
CEI and TE have been named as "potentially responsible parties"
(PRPs) at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of
1980. Allegations of disposal of hazardous substances at historical sites
and the liability involved, are often unsubstantiated and subject to
dispute. Federal law provides that all PRPs for a particular site be held
liable on a joint and several basis. CEI and TE have accrued liabilities
totaling $3.7 million as of December 31, 2000, based on estimates of the
total costs of cleanup, the proportionate responsibility of other PRPs for
such costs and the financial ability of other PRPs to pay. CEI and TE
believe that waste disposal costs will not have a material adverse effect
on their financial condition, cash flows or results of operations.
7. SEGMENT INFORMATION:
The Company operates under the following reportable segments:
regulated services, competitive services and other (primarily corporate
support services). The Company's primary segment is its regulated
services, which include five electric utility operating companies that
formerly provided bundled electric service in Ohio and Pennsylvania. Its
other material business segment consisted of the subsidiaries that operate
unregulated businesses. During 2000, the Company made certain
organizational changes to further align its business units to accommodate
its retail strategy and the impact of its plan to move the generation
portion of its electricity services from the regulated segment to the
competitive segment as reflected in its approved Ohio transition plan.
These reportable segments are strategic businesses, which are managed and
operated differently based on the degree of regulation, and the products
and services offered.
The regulated services segment designs, constructs, operates and
maintains our regulated transmission and distribution systems. It also
provides generation services to regulated franchise customers who have not
chosen an alternative, competitive generation supplier. The regulated
services segment obtains generation through power supply agreements with
the competitive services segment.
The competitive services segment includes all unregulated energy
and energy-related services including commodity sales (both electricity
and natural gas) in the retail and wholesale markets, marketing,
generation, trading and sourcing of commodity requirements, as well as
other competitive energy-application services. Competitive products are
increasingly marketed to customers as bundled services.
Segment Financial Information
-----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
--------- ----------- ----- ----------- ------------
(In millions)
2000
----
External revenues $ 4,747 $2,020 $ 8 $ 254 (A) $ 7,029
Intersegment revenues 28 1,827 303 (2,158)(B) --
Total revenues 4,775 3,847 311 (1,904) 7,029
Depreciation and amortization 790 194 13 (63)(C) 934
Income taxes 561 68 1 (253)(D) 377
Net operating profit after taxes 916 128 3 (448)(E) 599
Total assets 15,688 1,933 320 -- 17,941
1999
----
External revenues $ 4,723 $1,218 $ 16 $ 363 (A) $ 6,320
Intersegment revenues 55 1,301 181 (1,537)(B) --
Total revenues 4,778 2,519 197 (1,174) 6,320
Depreciation and amortization 789 170 9 (30)(C) 938
Income taxes 574 75 (32) (222)(D) 395
Net operating profit after taxes 977 126 (61) (474)(E) 568
Total assets 15,931 1,514 779 -- 18,224
1998
----
External revenues $ 4,802 $ 934 $ 8 $ 131 (A) $ 5,875
Intersegment revenues -- 2,806 144 (2,950)(B) --
Total revenues 4,802 3,740 152 (2,819) 5,875
Depreciation and amortization 784 8 5 (38)(C) 759
Income taxes 822 (40) (22) (456)(D) 304
Net operating profit after taxes 893 (59) (43) (350)(E) 441
Total assets 15,918 1,558 716 -- 18,192
<FN>
Reconciling adjustments to segment operating results from internal management reporting to
consolidated external financial reporting:
(A) Principally interest income and revenues related to gross receipts taxes which are
excluded for internal management reporting purposes.
(B) Elimination of intersegment revenues.
(C) Reclassification for amortization of tax regulatory assets included in income
taxes for external financial reporting; reduction for depreciation expense
recognized for internal management reporting for assets subject to sale and
leaseback transactions (see Note 3); and recognition of goodwill amortization
which is excluded for internal management reporting.
(D) Income tax effects of the differences described above and the tax benefit of
interest expense not otherwise included in the computation of net operating
profit after taxes.
(E) The net effect from the differences described above and the recognition of
interest costs not included in net operating profit after taxes for internal
management reporting purposes.
Products and Services
---------------------
Oil & Gas Energy Related
Electricity Sales and Sales and
Year Sales Production Services
---- ----------- ---------- --------------
(In millions)
2000 $5,537 $582 $563
1999 5,253 203 503
1998 4,980 26 198
8. 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, except per share amounts)
Revenues $1,607.9 $1,702.1 $1,891.7 $1,827.3
Expenses 1,234.1 1,338.0 1,433.1 1,518.9
- -----------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes 373.8 364.1 458.6 308.4
Net Interest Charges 135.0 134.4 131.2 128.5
Income Taxes 97.9 95.1 129.2 54.6
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Net Income $ 140.9 $ 134.6 $ 198.2 $ 125.3
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Earnings per Share of Common Stock $ .63 $ .60 $ .89 $ .57
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March 31, June 30, September 30, December 31,
Three Months Ended 1999 1999 1999 1999
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(In millions, except per share amounts)
Revenues $1,417.4 $1,523.9 $1,732.4 $1,645.9
Expenses 1,041.7 1,149.8 1,291.0 1,301.7
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Income Before Interest and Income Taxes 375.7 374.1 441.4 344.2
Net Interest Charges 146.1 147.4 141.3 137.5
Income Taxes 92.9 101.4 114.3 86.2
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Net Income $ 136.7 $ 125.3 $ 185.8 $ 120.5
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Earnings per Share of Common Stock $ .60 $ .55 $ .82 $ .53
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