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 six 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 four
meetings in 2001.
Richard H. Marsh
Senior Vice President
and Chief Financial Officer
Harvey L. Wagner
Vice President, 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, 2001 and 2000, 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, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of FirstEnergy Corp.
and subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the consolidated financial statements,
effective January 1, 2001, the Company changed its method of accounting for
derivative instruments and hedging activities by adopting Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.
FIRSTENERGY CORP.
SELECTED FINANCIAL DATA
For the Years Ended December 31, 2001 2000 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
Revenues....................................... $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906 $ 2,961,125
-----------------------------------------------------------------------
Income Before Extraordinary Item and
Cumulative Effect of Accounting Change...... $ 654,946 $ 598,970 $ 568,299 $ 441,396 $ 305,774
-----------------------------------------------------------------------
Net Income..................................... $ 646,447 $ 598,970 $ 568,299 $ 410,874 $ 305,774
-----------------------------------------------------------------------
Basic Earnings per Share of Common Stock:
Before Extraordinary Item and Cumulative
Effect of Accounting Change $2.85 $2.69 $2.50 $1.95 $1.94
After Extraordinary Item and Cumulative
Effect of Accounting Change............... $2.82 $2.69 $2.50 $1.82 $1.94
-----------------------------------------------------------------------
Diluted Earnings per Share of Common Stock:
Before Extraordinary Item and Cumulative
Effect of Accounting Change............... $2.84 $2.69 $2.50 $1.95 $1.94
After Extraordinary Item and Cumulative
Effect of Accounting Change............... $2.81 $2.69 $2.50 $1.82 $1.94
-----------------------------------------------------------------------
Dividends Declared per Share of Common Stock... $1.50 $1.50 $1.50 $1.50 $1.50
-----------------------------------------------------------------------
Total Assets................................... $37,351,513 $17,941,294 $18,224,047 $18,192,177 $18,261,481
-----------------------------------------------------------------------
Capitalization at December 31:
Common Stockholders' Equity................. $ 7,398,599 $ 4,653,126 $ 4,563,890 $ 4,449,158 $ 4,159,598
Preferred Stock:
Not Subject to Mandatory Redemption....... 480,194 648,395 648,395 660,195 660,195
Subject to Mandatory Redemption........... 594,856 161,105 256,246 294,710 334,864
Long-Term Debt*............................. 12,865,352 5,742,048 6,001,264 6,352,359 6,969,835
-----------------------------------------------------------------------
Total Capitalization*..................... $21,339,001 $11,204,674 $11,469,795 $11,756,422 $12,124,492
=======================================================================
<FN>
* 2001 includes approximately $1.4 billion of long-term debt (excluding
long-term debt due to be repaid within one year) included in "Liabilities
Related to Assets Pending Sale" on the Consolidated Balance Sheet as of
December 31, 2001.
</FN>
PRICE RANGE OF COMMON STOCK
The Common Stock of FirstEnergy Corp. is listed on the New York
Stock Exchange and is traded on other registered exchanges.
2001 2000
- ----------------------------------------------------------------------------
First Quarter High-Low....... $31.75 $25.10 $23.56 $18.00
Second Quarter High-Low...... 32.20 26.80 26.88 20.56
Third Quarter High-Low....... 36.28 29.60 27.88 22.94
Fourth Quarter High-Low...... 36.98 32.85 32.13 24.11
Yearly High-Low.............. 36.98 25.10 32.13 18.00
- ----------------------------------------------------------------------------
Prices are based on reports published in The Wall Street Journal for New York
-----------------------
Stock Exchange Composite Transactions.
HOLDERS OF COMMON STOCK
There were 173,121 and 172,285 holders of 297,636,276 shares of FirstEnergy's
Common Stock as of December 31, 2001 and January 31, 2002, 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, our ability to accomplish or realize
anticipated benefits from strategic initiatives and other similar factors.
FirstEnergy Corp. is a holding company that provides regulated and
competitive energy services (see Results of Operations - Business Segments)
domestically and internationally. The international operations were acquired as
part of FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU Capital,
Inc. and its subsidiaries provide electric distribution services in foreign
countries. GPU Power, Inc. and its subsidiaries develop, own and operate
generation facilities in foreign countries. Sales are pending for portions of
the international operations (see Capital Resources and Liquidity). Prior to the
GPU merger, regulated electric distribution services were provided to portions
of Ohio and Pennsylvania by our wholly owned subsidiaries - Ohio Edison Company
(OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power
Company (Penn) and The Toledo Edison Company (TE) with American Transmission
Systems, Inc. (ATSI) providing transmission services. Following the GPU merger,
regulated services are also provided through wholly owned subsidiaries - Jersey
Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and
Pennsylvania Electric Company (Penelec) - which provide electric distribution
and transmission services to portions of Pennsylvania and New Jersey. The
coordinated delivery of energy and energy-related products to customers in
unregulated markets is provided through a number of subsidiaries, often under
master contracts providing for the delivery of multiple energy and
energy-related services. Prior to the GPU merger, competitive services were
principally provided by FirstEnergy Solutions Corp. (FES), FirstEnergy
Facilities Services Group, LLC (FEFSG) and MARBEL Energy Corporation. Following
the GPU merger, competitive services are also provided through GPU Advanced
Resources, Inc. and MYR Group, Inc.
GPU Merger
On November 7, 2001, the merger of FirstEnergy and GPU became
effective with FirstEnergy being the surviving company. The merger was accounted
for using purchase accounting under the guidelines of Statement of Financial
Accounting Standards No. (SFAS) 141, "Business Combinations." Under purchase
accounting, the results of operations for the combined entity are reported from
the point of consummation forward. As a result, FirstEnergy's financial
statements for 2001 reflect twelve months of operations for FirstEnergy's
pre-merger organization and only seven weeks of operations (November 7, 2001 to
December 31, 2001) for the former GPU companies. Additional goodwill resulting
from the merger ($2.3 billion) plus goodwill existing at GPU ($1.9 billion) at
the time of the merger is not being amortized, reflecting the application of
SFAS 142, "Goodwill and Other Intangible Assets." Goodwill continues to be
subject to review for potential impairment (see Recently Issued Accounting
Standards). Prior to consummation of the GPU merger we identified certain GPU
international operations (see Note 2 - Divestitures-International Operations)
providing gas transmission and electric distribution services for divestiture
within twelve months of the merger date. These operations constitute individual
"lines of business" as defined in Accounting Principles Board Opinion (APB) No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions" with physically and operationally separable activities.
Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of
Purchase Price to Assets to Be Sold," requires that expected, pre-sale cash
flows (including incremental interest costs on related acquisition debt) of
these operations be considered part of the purchase price allocation.
Accordingly, subsequent to the merger date, results of operations (and related
interest expense) of these international subsidiaries have not been included in
FirstEnergy's Consolidated Statement of Income. Additionally, assets and
liabilities of these international operations have been segregated under
separate captions - "Assets Pending Sale" and "Liabilities Related to Assets
Pending Sale" on FirstEnergy's Consolidated Balance Sheet.
Results of Operations
Net income increased to $646.4 million in 2001, compared to $599.0
million in 2000 and $568.3 million in 1999. Net income in 2001 included an
after-tax charge of $8.5 million resulting from the cumulative effect of an
accounting change due to the adoption of SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities." Excluding the seven weeks of the former GPU
companies' results (and related interest expense on acquisition debt), net
income increased to $613.7 million in 2001 due to reduced depreciation and
amortization, general taxes and net interest
charges. The benefit of these reductions was offset in part by lower retail
electric sales, increased other operating expenses and higher gas costs. In
2000, lower fuel costs, increased generation output, reduced financing costs and
gains realized on the sale of emission allowances contributed to the increase in
net income from the prior year.
Total revenues increased $970.4 million in 2001 compared to 2000.
Excluding the seven weeks of results from the former GPU companies, total
revenues increased $336.7 million following a $709.3 million increase in 2000.
In both 2001 and 2000, the additional sales resulted from an expansion of our
unregulated businesses, which more than offset lower sales from our electric
utility operating companies (EUOC). Sources of changes in pre-merger and
post-merger companies' revenues during 2001 and 2000, compared to the prior
year, are summarized in the following table:
Sources of Revenue Changes 2001 2000
----------------------------------------------------------------------
Increase (Decrease) (In millions)
Pre-Merger Companies:
Electric Utilities (Regulated Services):
Retail electric sales................... $(240.5) $(36.8)
Other revenues.......................... (22.6) 4.7
----------------------------------------------------------------------
Total Electric Utilities.................. (263.1) (32.1)
----------------------------------------------------------------------
Unregulated Businesses (Competitive Services):
Retail electric sales................... (19.9) 170.7
Wholesale electric sales................ 287.1 105.7
Gas sales............................... 226.1 376.3
Other revenues.......................... 106.5 88.7
----------------------------------------------------------------------
Total Unregulated Businesses.............. 599.8 741.4
----------------------------------------------------------------------
Total Pre-Merger Companies................ 336.7 709.3
----------------------------------------------------------------------
Former GPU Companies:
Electric utilities...................... 570.4 --
Unregulated businesses.................. 101.9 --
----------------------------------------------------------------------
Total Former GPU Companies................ 672.3 --
Intercompany Revenues..................... (38.6) --
----------------------------------------------------------------------
Net Revenue Increase...................... $970.4 $709.3
======================================================================
Electric Sales
EUOC retail electric sales revenues for our pre-merger companies
decreased by $240.5 million in 2001, compared to 2000, primarily due to lower
generation kilowatt-hour sales reflecting the result of customer choice in Ohio
and the influence of a declining national economy on our regional business
activity, which reduced our distribution deliveries. Both unit prices and sales
volumes declined from the prior year. As a result of opening Ohio to competing
generation suppliers in 2001, sales of electric generation by alternative
suppliers in our franchise area increased to 11.3% of total energy delivered,
compared to 0.8% in 2000. Consequently, generation kilowatt-hour sales to retail
customers were 12.2% lower in 2001 than the prior year. Implementation of a 5%
reduction in generation charges for residential customers as part of Ohio's
electric utility restructuring implemented in 2001, also contributed $51.2
million to the reduced electric sales revenues. Weather in 2001 had a minor
influence on sales with mild weather in the fourth quarter substantially
offsetting a net increase in weather-related sales revenue through the third
quarter. Kilowatt-hour deliveries to franchise customers were down a more
moderate 1.7% due in part to the decline in economic conditions, which was a
major factor resulting in a 3.1% decrease in kilowatt-hour deliveries to
commercial and industrial customers. Other regulated electric revenues decreased
by $22.6 million in 2001, compared to the prior year, due in part to reduced
customer reservation of transmission capacity.
Total electric generation sales increased by 8.3% in 2001 compared to
the prior year with sales to the wholesale market being the largest single
factor contributing to this increase. While revenues from the wholesale market
increased $287.1 million in 2001 from the prior year, kilowatt-hour sales to
that market more than doubled as nonaffiliated energy suppliers made use of the
1,120 megawatts (MW) supply commitment under our Ohio transition plan, and
reduced sales to the regulated retail market made additional energy available to
pursue opportunities in the wholesale market. Retail kilowatt-hour sales by our
competitive services segment increased by 10.6% in 2001, compared to 2000. The
increase resulted from expanding kilowatt-hour sales within Ohio as a result of
retail customers switching to FES, our unregulated subsidiary, under Ohio's
electricity choice program. The higher kilowatt-hour sales in Ohio were
partially offset by lower sales in markets outside of Ohio as more customers
returned to their local distribution companies. Declining sales to higher-priced
eastern markets contributed to an overall decline in retail competitive sales
revenue in 2001 from the prior year, despite an increase in kilowatt hour sales
in Ohio's competitive market.
EUOC retail revenues decreased by $36.8 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% 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 in 2000 reflecting our marketing
efforts to expand retail electric sales to targeted unregulated markets in the
eastern seaboard states, principally the commercial and industrial sectors. The
cooler summer weather reduced retail customer demand, making more of our energy
available to 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 revenue.
Changes in electric generation sales and distribution deliveries in
2001 and 2000 for our pre-merger companies are summarized in the following
table:
Changes in Kilowatt-hour Sales 2001 2000
------------------------------------------------------------------
Increase (Decrease)
Electric Generation Sales:
Retail --
Regulated services............... (12.2)% 2.0%
Competitive services............. 10.6% 229.6%
Wholesale.......................... 165.5% 7.4%
------------------------------------------------------------------
Total Electric Generation Sales...... 8.3% 8.4%
==================================================================
EUOC Distribution Deliveries:
Residential........................ 1.7% (1.2)%
Commercial and industrial.......... (3.1)% 2.9%
------------------------------------------------------------------
Total Distribution Deliveries........ (1.7)% 1.7%
==================================================================
Other Sales
Natural gas revenues were the largest source of increases in other
sales in 2001. Beginning November 1, 2000, residential and small business
customers in the service area of Dominion East Ohio, a nonaffiliated gas
utility, began shopping among alternative gas suppliers as part of a customer
choice program. FES took advantage of this opportunity to expand its customer
base. The average number of retail gas customers served by FES increased to
approximately 161,000 in 2001 from approximately 44,000 in 2000. Total gas sales
increased by $226.1 million or 40% from the prior year. In 2000, retail natural
gas revenues were the largest source of increase in other sales. 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. Wholesale gas revenues were
also higher.
Expenses
Total expenses increased $790.2 million in 2001, which included $542.4
million of incremental expenses for the former GPU companies during the last
seven weeks of 2001. For our pre-merger companies, total expenses increased
$280.4 million in 2001 and $739.8 million in 2000, compared to the prior year.
Sources of changes in pre-merger and post-merger companies' expenses in 2001 and
2000, compared to the prior year, are summarized in the following table:
Sources of Expense Changes 2001 2000
-------------------------------------------------------------------
Increase (Decrease) (In millions)
Pre-Merger Companies:
Fuel and purchased power................ $ 48.7 $125.9
Purchased gas........................... 266.5 382.9
Other operating expenses................ 178.2 231.7
Depreciation and amortization........... (99.0) (4.3)
General taxes........................... (114.0) 3.6
-------------------------------------------------------------------
Total Pre-Merger Companies................ 280.4 739.8
-------------------------------------------------------------------
Former GPU Companies...................... 542.4 --
Intercompany Expenses..................... (32.6) --
-------------------------------------------------------------------
Net Expense Increase...................... $790.2 $739.8
===================================================================
The following comparisons reflect variances for the pre-merger
companies only, excluding the incremental expenses for the former GPU companies
during the last seven weeks of 2001.
The increase in fuel expense in 2001 compared to 2000 ($24.3 million)
resulted from the substitution of coal and natural gas fired generation for
nuclear generation (which has lower unit fuel costs than fossil fuel) during a
period of reduced nuclear availability resulting from both planned and unplanned
outages. Coal prices were also higher during that period. Purchased power costs
increased early in 2001, compared to 2000, due to higher winter prices and
additional purchased power requirements during that period, with the balance of
the year offsetting all but $24.4 million of that increase, reflecting generally
lower prices and reduced external power needs than last year's.
In 2000, fuel and purchased power increased $125.9 million due to a
$201.6 million increase in fuel and purchased power expense of FirstEnergy
Trading Services Inc. (FETS), a wholly owned subsidiary, reflecting expansion of
its operations to support our retail marketing efforts (FETS operations were
assumed by FES in 2001). Excluding those competitive activities, fuel and
purchased power costs 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 the output from our generating units due to
additional nuclear generation, the expiration of an above-market coal contract
and continued improvement in coal blending strategies. Purchased power costs
increased $27.9 million in 2000 from the prior year due to higher average prices
and to additional kilowatt-hours purchased. Purchased gas costs increased 48% in
2001 and 224% in 2000 from the prior year. The increases were due principally to
the expansion of FES's retail gas business.
Other operating expenses increased by $178.2 million in 2001 and by
$231.7 million in 2000 compared to the prior year. The significant reduction in
2001 of gains from the sale of emission allowances, higher fossil operating
costs and additional employee benefit costs accounted for $144.5 million of the
increase in 2001. Additionally, higher operating costs from the competitive
services business segment due to expanded operations contributed $56.9 million
to the increase. Partially offsetting these higher other operating expenses was
a reduction in low-income payment plan customer costs and a $30.2 million
decrease in nuclear operating costs in 2001, compared to the prior year,
resulting from one less refueling outage.
Fossil operating costs increased $44.3 million in 2001 from last year
due principally to planned maintenance work at the Mansfield generating plant.
Pension costs increased by $32.6 million in 2001 from the prior year primarily
due to lower returns on pension plan assets (due to significant market-related
reductions in the value of pension plan assets), the completion of the 15-year
amortization of OE's pension transition asset and changes to plan benefits.
Health care benefit costs also increased by $21.4 million in 2001, compared to
2000, principally due to an increase in the health care cost trend rate
assumption for computing post-retirement health care benefit liabilities.
In 2000, other operating expenses increased from 1999 due to several
factors. A significant portion of the increase resulted from additional nuclear
costs associated with three refueling outages in 2000 versus two during the
previous year and increased nuclear ownership resulting from the Duquesne asset
exchange. 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.
We also incurred increased reserves for potentially uncollectible accounts from
customers in the steel sector as well as a reserve for expected construction
contract losses at FEFSG. The increase in other operating costs in 2000 from
1999 also reflected an increase in expenses related to expanded operations of
the competitive services business segment. Partially offsetting the higher costs
were increased gains of $38.5 million realized from the sale of emission
allowances in 2000 as well as the absence of nonrecurring costs recognized in
the prior year.
Charges for depreciation and amortization decreased by $99.0 million
in 2001 and $4.3 million in 2000 from the prior year. Approximately $64.6
million of the decrease in 2001 resulted from lower incremental transition cost
amortization under FirstEnergy's Ohio transition plan compared to accelerated
cost recovery in connection with OE's prior rate plan. The reduction in
depreciation and amortization also reflected additional cost deferrals of $51.2
million for recoverable shopping incentives under the Ohio transition plan,
partially offset by increases associated with depreciation on recently completed
combustion turbines.
In November 2001, we announced an agreement to sell four of our
coal-fired power plants to NRG Energy, Inc. The plants meet the criteria under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" and have been classified as assets to be disposed of
since November 2001. Accordingly, depreciation of those plants ceased pending
their sale. Due to the cessation of depreciation on those plants, depreciation
was reduced by $6.6 million in 2001 from what it otherwise would have been.
Under SFAS 121 guidance, the long-lived assets to be disposed of must be
included on the balance sheet at the lower of their carrying amount or fair
value less cost to sell (see Outlook - Optimizing the Use of Assets) and at year
end continued to be reported at their carrying amount of $539 million.
In 2000, depreciation and amortization was reduced by $9.8 million in
the second half of the year, following approval by the Public Utilities
Commission of Ohio (PUCO) of FirstEnergy's Ohio transition plan. Incremental
transition costs recovered in 2001 and cost recovery accelerated under OE's rate
plan and Penn's restructuring plan in 2000 and 1999 are summarized by income
statement caption in the following table:
Accelerated Cost Recovery 2001 2000 1999
------------------------------------------------------------------------
(In millions)
Depreciation and amortization.. $268.0 $332.6 $333.3
Income tax amortization........ 41.1 42.6 18.7
------------------------------------------------------------------------
Total Accelerations............ $309.1 $375.2 $352.0
========================================================================
General taxes declined $114.0 million from last year primarily due to
reduced property taxes and other state tax changes in connection with the Ohio
electric industry restructuring. In addition, as a result of successfully
resolving certain pending tax issues, a one-time benefit of $15 million was also
recognized in 2001. The reduction in general taxes was partially offset by $66.6
million of new Ohio franchise taxes, which are classified as state income taxes
on the Consolidated Statements of Income.
Net Interest Charges
Net interest charges increased $26.6 million in 2001, compared to
2000. This increase reflects interest on $4 billion of long-term debt issued by
FirstEnergy in connection with the merger and related bridge financing, which
totaled $40.4 million. Excluding the results associated with the last seven
weeks of 2001 for the former GPU companies and merger-related financing, net
interest charges decreased $39.8 million in 2001, compared to a $43.2 million
decrease in 2000 from the prior year. We continued to redeem and refinance our
outstanding debt and preferred stock, maintaining a downward trend in financing
costs during 2001, before the effects of the GPU merger.
After the merger with GPU became probable, we established cash flow
hedges under SFAS 133 covering a portion of our future interest payments in
connection with the anticipated issuance of $4 billion of acquisition-related
debt. The hedges provided us with protection against a possible upward move in
interest rates but limited our ability to completely participate in the benefits
of a downward move. Due to a decline in interest rates during the period in
which cash flow hedges were in place, FirstEnergy incurred a net deferred loss
in connection with this transaction and a related reduction in other
comprehensive income totaling $134 million (after tax). The cash flow hedges
were the primary contributor to the current net deferred loss of $169.4 million
included in Accumulated Other Comprehensive Loss (AOCL) as of December 31, 2001
for derivative hedging activity. In accordance with the requirements of SFAS
133, this amount is being amortized from AOCL to interest expense over the
corresponding interest payment periods hedged - 5, 10 and 30 years.
Results of Operations - Business Segments
We manage our business as two separate major business segments -
regulated services and competitive services. The regulated services segment
designs, constructs, operates and maintains our regulated domestic transmission
and distribution systems. It also provides generation services to franchise
customers who have not chosen an alternative generation supplier. OE, CEI and TE
(Ohio Companies) and Penn obtain generation through a power supply agreement
with the competitive services segment (see Outlook - Business Organization). 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, often under master contracts. Financial results discussed below
include intersegment revenue. A reconciliation of segment financial results to
consolidated financial results is provided in Note 7 to the consolidated
financial statements.
Regulated Services
Net income increased to $640.2 million in 2001, compared to $464.4
million in 2000 and $413.9 million in 1999. Excluding the last seven weeks of
2001 results associated with the former GPU companies, net income increased by
$98.7 million in 2001. The increases in pre-merger net income are summarized in
the following table:
Regulated Services 2001 2000
----------------------------------------------------------------------
Increase (Decrease) (In millions)
Revenues.................................... $(130.2) $ 57.5
Expenses.................................... (345.2) 54.1
---------------------------------------------------------------------
Income Before Interest and Income Taxes..... 215.0 3.4
---------------------------------------------------------------------
Net interest charges........................ (16.8) (55.9)
Income taxes................................ 133.1 8.8
---------------------------------------------------------------------
Net Income Increase......................... $ 98.7 $ 50.5
=====================================================================
Distribution throughput was 1.7% lower in 2001, compared to 2000,
reducing external revenues by $245.7 million. Partially offsetting the decrease
in external revenues were revenues from FES for the rental of fossil generating
facilities and the sale of generation from nuclear plants, resulting in a net
$130.2 million reduction to total revenues. Expenses were $345.2 million lower
in 2001 than 2000 due to lower purchased power, depreciation and amortization
and general taxes, offset in part by higher other operating expenses. Lower
generation sales reduced the need to purchase power from FES, with a resulting
$269.0 million decline in those costs in 2001 from the prior year. Other
operating expenses increased by $178.5 million in 2001 from the previous year
reflecting a significant reduction in 2001 of gains from the sale of emission
allowances, higher fossil operating costs and additional employee benefit costs.
Lower incremental transition cost amortization and the new shopping incentive
deferrals under FirstEnergy's Ohio transition in 2001 plan as compared with the
accelerated cost recovery in connection with OE's prior rate plan in 2000
resulted in a $131.0 million reduction in depreciation and amortization in 2001.
A $123.6 million decrease in general taxes in 2001 from the prior year primarily
resulted from reduced property taxes and other state tax changes in connection
with the Ohio electric industry restructuring.
Lower unit prices in 2000 compared to 1999 produced a $33.2 million
decrease in revenues from nonaffiliates despite a 1.7% increase in kilowatt-hour
deliveries. Rental of fossil generating facilities and the sale of generation
from nuclear plants more than offset the reduced external revenue resulting in a
net $57.5 million increase in total revenues. Expenses increased $54.1 million
in 2000 from 1999 primarily due to higher purchased power costs resulting from
higher average prices and additional megawatt-hours purchased, as well as higher
other operating costs. Interest charges in 2000 decreased $55.9 million compared
to 1999, reflecting the impact of net debt redemptions and refinancings and was
the primary contributor to the increase in net income.
Competitive Services
Net income decreased to $57.2 million in 2001, compared to $137.2
million in 2000 and $129.2 million in 1999. Excluding the last seven weeks of
2001 results associated with the former GPU companies, net income decreased
$83.0 million in 2001. The changes to pre-merger net income are summarized in
the following table:
Competitive Services 2001 2000
----------------------------------------------------------------------
Increase (Decrease) (In millions)
Revenue..................................... $254.1 $789.6
Expenses.................................... 366.9 773.5
----------------------------------------------------------------------
Income Before Interest and Income Taxes..... (112.8) 16.1
----------------------------------------------------------------------
Net interest charges........................ 13.5 2.6
Income taxes................................ (51.8) 5.5
Cumulative effect of a change in accounting. (8.5) --
---------------------------------------------------------------------
Net Income Increase (Decrease).............. $(83.0) $ 8.0
======================================================================
Sales to nonaffiliates increased $523.1 million in 2001, compared to
the prior year, with electric revenues contributing $260.1 million, natural gas
revenues $226.1 million and the balance of the increase from energy-related
services. Reduced power requirements by the regulated services segment reduced
internal revenues by $269.0 million. Expenses increased $366.9 million in 2001
from 2000 primarily due to a $266.5 million increase in purchased gas costs and
increases resulting from additional fuel and purchased power costs (see Results
of Operations) as well as higher expenses for energy-related services. Reduced
margins for both major competitive product areas - electricity and natural gas -
contributed to the reduction in net income, along with higher interest charges
and the cumulative effect of the SFAS 133 accounting change. Margins for
electricity and gas sales were both adversely affected by higher fuel costs.
In 2000, sales to nonaffiliates increased $749.3 million, compared to
the prior year, with electric revenues contributing $283.5 million, natural gas
revenues $376.3 million and the balance of the increase from energy-related
services. Additional power sales to the regulated services segment increased
revenues by $40.3 million. Expenses
increased $773.6 million in 2000 from 1999 primarily due to the additional
purchased gas and purchased power costs resulting from the increased sales. The
exchange of fossil assets for nuclear assets with Duquesne Light Company in
December 1999 changed the mix of expenses, increasing plant operating costs and
decreasing fuel expense. The resulting net income increase primarily reflected
the contribution of competitive electric sales offset in part by higher interest
charges.
Capital Resources and Liquidity
We had approximately $220.2 million of cash and temporary investments
and $614.3 million of short-term indebtedness on December 31, 2001. Our unused
borrowing capability included $1.115 billion under revolving lines of credit and
$84 million from unused bank facilities. At the end of 2001, OE, CEI, TE and
Penn had the capability to issue $2.2 billion of additional first mortgage bonds
(FMB) on the basis of property additions and retired bonds. The former GPU EUOC
will not issue FMB other than as collateral for senior notes, since their senior
note indentures prohibit (subject to certain exceptions) the GPU EUOC from
issuance of any debt which is senior to the senior notes. As of December 31,
2001, the GPU EUOC had the capability to issue $795 million of additional senior
notes based upon FMB collateral. At year end 2001, based upon applicable
earnings coverage tests and their respective charters, OE, Penn, TE and JCP&L
could issue $7.0 billion of preferred stock (assuming no additional debt was
issued). CEI, Met-Ed and Penelec have no restrictions on the issuance of
preferred stock.
At the end of 2001, our common equity as a percentage of
capitalization, including debt relating to assets held for sale, stood at 35%
compared to 42% at the end of 2000. This decrease resulted from the addition of
$8.2 billion of debt, $378 million of preferred stock and $2.6 billion of common
stock (issued to former GPU stockholders) to our capital structure as a result
of the GPU acquisition. The incremental debt included $6.0 billion of the former
GPU companies' debt, $1.5 billion of which was replaced with FirstEnergy debt
and an additional $2.2 billion of FirstEnergy debt used to pay GPU shareholders
as part of the merger.
Following approval of our merger with GPU by the New Jersey Board of
Public Utilities (NJBPU) on September 26, 2001 and by the Securities and
Exchange Commission on October 29, 2001, Standard & Poor's (S&P) and Moody's
Investors Service established initial credit ratings for FirstEnergy's holding
company and adjusted those of our EUOC to reflect our new consolidated credit
profile. S&P's outlook on all our credit ratings is stable. On February 22,
2002, Moody's announced a change in its outlook for the credit ratings of
FirstEnergy, Met-Ed and Penelec from stable to negative. The change was based
upon a decision by the Commonwealth Court of Pennsylvania to remand to the
Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision
regarding rate relief, accounting deferrals and the mechanism for sharing merger
savings rendered in connection with its approval of the GPU merger (see State
Regulatory Matters-Pennsylvania).
Our cash requirements in 2002 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Major contractual obligations for future cash payments are
summarized in the following table:
Contractual Obligations 2002 2003 2004 2005 2006 Thereafter Total
- -------------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt*................ $1,205 $ 711 $1,179 $ 854 $1,433 $ 7,596 $12,978
Short-term borrowings*......... 614 -- -- -- -- -- 614
Mandatory preferred stock...... 30 13 13 4 4 572 636
Capital leases ................ 6 6 6 5 6 10 39
Operating leases .............. 153 156 184 186 183 2,036 2,898
Unconditional fuel and power
purchases................... 2,493 1,584 1,369 1,219 1,250 6,056 13,971
- --------------------------------------------------------------------------------------------------------------
Total* $4,501 $2,470 $2,751 $2,268 $2,876 $16,270 $31,136
==============================================================================================================
<FN>
* Excludes approximately $1.75 billion of long-term debt and $233.8 million of
short-term borrowings related to pending divestitures discussed below.
</FN>
Our capital spending for the period 2002-2006 is expected to be about
$3.4 billion (excluding nuclear fuel), of which approximately $850 million
applies to 2002. Investments for additional nuclear fuel during the 2002-2006
period are estimated to be approximately $536 million, of which about $54
million applies to 2002. During the same period, our nuclear fuel investments
are expected to be reduced by approximately $507 million and $101 million,
respectively, as the nuclear fuel is consumed.
Off balance sheet obligations primarily consist of sale and leaseback
arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce
Mansfield Plant, which are reflected in the operating lease payments disclosed
above (see Note 3). The present value as of December 31, 2001, of these sale and
leaseback operating lease commitments,
net of trust investments, total $1.5 billion. CEI and TE sell substantially all
of their retail customer receivables, which provided $200 million of off balance
sheet financing as of December 31, 2001 (see Note 1 - Revenues).
FirstEnergy's sale of the former GPU subsidiary, GasNet, in December
2001, eliminated $290 million of debt and also provided $125 million of net cash
proceeds, which were used to reduce short-term borrowings. Expected proceeds
from the pending sales of four fossil plants and Avon Energy Partners Holdings,
a wholly owned subsidiary, are shown in the following table:
Completed and Pending Divestitures
Cash Debt
Proceeds Removed Transaction Date**
- --------------------------------------------------------------------------------
Completed Sale
--------------
GasNet $125 million $290 million December 2001
Pending Sales:
--------------
Avon Energy $238 million* $1.7 billion Second Quarter 2002
Lake Plants $1.355 billion $145 million Mid-2002
-------------------------------------------------------------------------------
* Based on receipt of $150 million at closing and the present value of $19
million per year to be received over six years beginning in 2003.
** Estimated closing dates for pending sales.
FirstEnergy continues to pursue divestiture of the remainder of its
international operations (see Outlook - Optimizing the Use of Assets).
Market Risk Information
We use various market risk sensitive instruments, including derivative
contracts, primarily to manage the risk of price, interest rate and foreign
currency fluctuations. Our Risk Policy Committee, comprised of executive
officers, exercises an independent risk oversight function to ensure compliance
with corporate risk management policies and prudent risk management practices.
Commodity Price Risk
We are exposed to market risk primarily due to fluctuations in
electricity, natural gas and coal prices. To manage the volatility relating to
these exposures, we use a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes and, to a much lesser
extent, for trading purposes. The change in the fair value of commodity
derivative contracts related to energy production during 2001 is summarized in
the following table:
Increase (Decrease)in the Fair Value of Commodity Derivative Contracts
------------------------------------------------------------------------
(In millions)
Outstanding as of January 1, 2001 with
SFAS 133 cumulative adjustment......................... $ 60.5
Acquisition of GPU....................................... 14.9
Contract value when entered.............................. 0.6
Increase/(decrease) in value of existing contracts....... (97.1)
Change in techniques/assumptions......................... --
Settled contracts........................................ (45.3)
----------------------------------------------------------------------
Outstanding as of December 31, 2001...................... $(66.4)*
======================================================================
* Does not include $11.6 million of derivative contract fair
value increase, as of December 31, 2001, representing our
50% share of Great Lakes Energy Partners, LLC
While the valuation of derivative contracts is always based on active
market prices when they are available, longer-term contracts can require the use
of model-based estimates of prices in later years due to the absence of
published market prices. We currently use modeled prices for the later years of
some electric contracts. Our model incorporates explicit assumptions regarding
future supply and demand and fuel prices. The model provides estimates of the
future prices for electricity and an estimate of price volatility. We make use
of these results in developing estimates of fair value for the later years of
those electric contracts for financial reporting purposes as well as for
internal management decision making. Sources of information for the valuation of
derivative contracts by year are summarized in the following table:
Source of Information - Fair Value by Contract Year
2002 2003 2004 Thereafter Total
- -----------------------------------------------------------------------------
(In millions)
Prices actively quoted... $(54.1) $(19.9) $ (3.2) $ -- $(77.2)
Prices based on models... -- -- (8.1) 18.9 10.8
--------------------------------------------------
Total................. $(54.1) $(19.9) $(11.3) $18.9 $(66.4)
=============================================================================
We perform sensitivity analyses 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 derivative
instruments would not have had a material effect on our consolidated financial
position or cash flows as of December 31, 2001. We estimate that if energy
commodity prices move on average 10 percent higher or lower, pretax income for
the next twelve months would increase or decrease, respectively, by
approximately $2.4 million.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is reduced since
a significant portion of our debt has fixed interest rates, as noted in the
table on the following page. We are subject to the inherent interest rate risks
related to refinancing maturing debt by issuing new debt securities. As
discussed in Note 3 to the consolidated financial statements, 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 to the consolidated financial
statements.
Comparison of Carrying Value to Fair Value
- ------------------------------------------------------------------------------------------------------------------
There- Fair
2002 2003 2004 2005 2006 after Total Value
- ------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than Cash
and Cash Equivalents:
Fixed Income................. $ 101 $ 97 $314 $ 58 $ 75 $1,901 $ 2,546 $ 2,568
Average interest rate..... 6.7% 7.7% 7.8% 7.9% 7.9% 6.6% 6.9%
- -------------------------------------------------------------------------------------------------------------------
___________________________________________________________________________________________________________________
Liabilities
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt:*
Fixed rate................... $1,089 $ 706 $923 $ 851 $1,411 $6,519 $11,499 $11,698
Average interest rate .... 8.2% 7.6% 7.2% 8.1% 5.8% 7.1% 7.2%
Variable rate.............. ..$ 35 $ 5 $256 $ 3 $ 22 $1,077 $ 1,398 $ 1,399
Average interest rate..... 5.2% 11.5% 3.1% 10.2% 5.2% 3.0% 3.1%
Short-term Borrowings*...... . $ 614 $ 614 $ 614
Average interest rate..... 2.8% 2.8%
- -------------------------------------------------------------------------------------------------------------------
Preferred Stock............. .$ 30 $ 13 $ 13 $ 4 $ 4 $ 572 $ 636 $ 626
Average dividend rate .... 8.7% 8.3% 8.3% 7.5% 7.5% 8.3% 8.3%
- -------------------------------------------------------------------------------------------------------------------
<FN>
* Excludes approximately $1.75 billion of long-term debt and $233.8 million of
short-term borrowings related to pending divestitures.
</FN>
Interest Rate Swap Agreements
Penelec, GPU Power through a subsidiary and GPU Electric, Inc.
(through GPU Power UK) use interest rate swap agreements, denominated in dollars
and sterling, to manage the risk of increases in variable interest rates. All of
the agreements convert variable rate debt to fixed rate debt. As of December 31,
2001, interest rate swaps denominated in dollars had a weighted average fixed
interest rate of 6.99%; those in sterling had a weighted average fixed interest
rate of 6.00%. The following summarizes the principal characteristics of the
swap agreements in effect as of December 31, 2001:
Interest Rate Swaps as of December 31, 2001
------------------------------------------------------------------
Notional Maturity Fair
Denomination Amount Date Value
------------ ------ ---- -----
(Dollars/Sterling in millions)
Dollars 50 2002 (1.8)
Dollars 26 2005 (1.1)
Sterling 125 2003 (2.3)
------------------------------------------------------------------
Foreign Currency Swap Agreements
GPU Electric uses currency swap agreements to manage currency risk
caused by fluctuations in the US dollar exchange rate related to bonds issued in
the US by Avon Energy, which owns GPU Power UK. These swap agreements convert
principal and interest payments on this US dollar debt to fixed sterling
principal and interest payments, and expire on the maturity dates of the bonds.
Interest expense is recorded based on the fixed sterling interest rate.
Characteristics of currency swap agreements outstanding as of December 31, 2001
are summarized in the following table:
Currency Swaps - Dollars/Sterling
-----------------------------------------------------------------------
Weighted
Notional Amount Maturity Average Interest Rate Fair
--------------------- ---------------------
USD Sterling Date USD Sterling Value
--------- -------- ---- --- -------- -----
(Dollars/Sterling in millions)
350 212 2002 6.73% 7.66% $46.3
250 152 2007 7.05% 7.72% $26.3
250 153 2008 6.46% 6.94% $23.7
-----------------------------------------------------------------------
Outlook
We continue to pursue our goal of being the leading regional supplier
of energy and related services in the northeastern quadrant of the United
States, where we see the best opportunities for growth. We intend to provide
competitively priced, high-quality products and value-added services - energy
sales and services, energy delivery, power supply and supplemental services
related to our core business. As our industry changes to a more competitive
environment, we have taken and expect to take actions designed to create a
larger, stronger regional enterprise that will be positioned to compete in the
changing energy marketplace.
Business Organization
Beginning in 2001, Ohio utilities that offered both competitive and
regulated retail electric services were required to implement a corporate
separation plan approved by the PUCO - one which provided a clear separation
between regulated and competitive operations. Our business is separated into
three distinct units - a competitive services unit, a regulated services unit
and a corporate support unit. FES provides competitive retail energy services
while the EUOC continue to provide regulated transmission and distribution
services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES,
leases fossil and hydroelectric plants from the EUOC and operates those plants.
We expect the transfer of ownership of EUOC generating assets to FGCO will be
substantially completed by the end of the market development period in 2005. All
of the EUOC power supply requirements for the Ohio Companies and Penn are
provided by FES to satisfy their "provider of last resort" (PLR) obligations, as
well as grandfathered wholesale contracts.
Optimizing the Use of Assets
A significant step toward being the leading regional supplier in our
target market was achieved when we merged with GPU in November, making us the
fourth largest investor-owned electric system in the nation based on the number
of customers served. Through the merger we can create a stronger enterprise with
greater resources and more opportunities to provide value to our customers,
shareholders and employees. However, additional steps must be taken in order to
deliver the full value of the merger. While GPU's former domestic electric
utility companies fit well with our regional market focus, GPU's former
international companies do not. In December 2001, we divested GasNet, an
Australian gas transmission company. Also, the sale of most of our interest in
Avon Energy - the holding company for Midlands Electricity plc - to Aquila, Inc.
(formerly UtiliCorp United) is pending. The transaction must be completed by
April 26, 2002, or either party may terminate the original agreement. On March
18, 2002, we announced that we finalized terms of the agreement under which
Aquila will acquire a 79.9 percent interest in Avon for approximately $1.9
billion (including the transfer of $1.7 billion of debt). We and Aquila together
will own all of the outstanding shares of Avon through a jointly owned
subsidiary, with each company having a 50-percent voting interest. GPU's other
foreign companies (excluding GPU Power) are held for sale including our
investment in Empresa Distribuidora Electrica Regional S.A. The pending
divestitures should increase our financial flexibility by reducing debt and
preferred stock, and aid us in providing more competitively priced products and
services.
On November 29, 2001, we announced an agreement to sell four of our
older coal-fired power plants located along Lake Erie in Ohio to NRG Energy,
Inc. Under the agreement, the Ashtabula, Bay Shore, Eastlake and Lake Shore
generating plants with a total net generating capacity of 2,535 MW will be sold.
The transaction includes our purchase of up to 10.5 billion kilowatt-hours of
electricity annually, similar to the average annual output of the plants,
through 2005 (the end of the market development period under Ohio's Electric
Choice Law). The transaction is subject to the receipt of
necessary regulatory approvals. This transaction is consistent with our strategy
of aggressively pursuing cost savings to maintain competitively priced products
and services. The sale will allow us to more closely match our generating
capabilities to the load profiles of our customers, resulting in more efficient
operation of our remaining generating units. It also enables us to concentrate
on our coal-fired generation along the Ohio River, which should contribute to
added supply efficiencies. The net, after-tax gain from the sale, based on the
difference between the sale price of the plants and their market price used in
our Ohio restructuring transition plan, will be credited to customers by
reducing the transition cost recovery period. We expect to use the net proceeds
from the sale for the redemption of high cost debt and preferred stock or to
reduce other outstanding obligations to provide additional cost savings.
State Regulatory Matters
As of January 1, 2001, customers in all of our service areas, covering
portions of Ohio, Pennsylvania and New Jersey, could select alternative energy
suppliers. Our EUOC continue to deliver power to homes and businesses through
their existing distribution systems, which remain regulated. Customer rates have
been restructured into separate components to support customer choice. In each
of the states, we have a continuing responsibility to provide power to those
customers not choosing to receive power from an alternative energy supplier,
subject to certain limits. However, despite similarities, the specific approach
taken by each state and for each of our regulated companies varies.
Regulatory assets are costs which the respective regulatory agencies
have authorized for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. The increase in
those assets in 2001 is primarily the result of the acquisition of the former
GPU companies. All of the regulatory assets are expected to continue to be
recovered under the provisions of the respective transition and regulatory plans
as discussed below. The regulatory assets of the individual companies are as
follows:
Regulatory Assets as of December 31,
- -----------------------------------------------------
Company 2001 2000
- ------- ---- ----
(In millions)
OE....................... $2,025.4 $2,238.6
CEI...................... 874.5 816.2
TE....................... 388.8 412.7
Penn..................... 208.8 260.2
Met-Ed................... 1,320.5 --
Penelec.................. 769.8 --
JCP&L.................... 3,324.8 --
-------- --------
Total................. $8,912.6 $3,727.7
======== ========
Ohio -
Beginning on January 1, 2001, Ohio customers were able to choose their
electricity suppliers. Customer rates of OE, CEI and TE were 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. Our Ohio EUOC have
continuing responsibility to provide energy to service-area customers as PLR
through December 31, 2005.
The transition cost portion of rates provides for recovery of certain
amounts not otherwise recoverable in a competitive generation market (such as
regulatory assets). Transition costs are paid by all customers whether or not
they choose an alternative supplier. Under the PUCO-approved transition plan, we
assumed the risk of not recovering up to $500 million of transition revenue if
the rate of customers (excluding contracts and full-service accounts) switching
their service from OE, CEI and TE does not reach 20% for any consecutive
twelve-month period by December 31, 2005 - the end of the market development
period. As of December 31, 2001, the customer switching rate, on an annualized
basis, implies that our risk of not recovering transition revenue has been
reduced to approximately $174 million. 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 December 31, 2001,
approximately 1,032 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 December 31, 2001 our Ohio EUOC
had been notified that over 600,000 of their customers requested generation
services from other authorized suppliers, including FES, a wholly owned
subsidiary.
Pennsylvania -
Choice of energy suppliers by Pennsylvania customers was phased in
starting in 1999 and was completed by January 1, 2001. The Pennsylvania Public
Utility Commission (PPUC) authorized rate restructuring plans for Penn, Met-Ed
and Penelec, establishing separate charges for transmission, distribution,
generation and stranded cost recovery, which is recovered through a "competitive
transition charge" (CTC). Pennsylvania customers electing to obtain power from
an alternative supplier have their bills reduced based on the regulated
generation component, and the customers receive a generation charge from the
alternative supplier.
In June 2001, Met-Ed, Penelec and FirstEnergy entered into a
settlement agreement with major parties in the combined merger and rate
proceedings that, in addition to resolving certain issues concerning the PPUC's
approval of the GPU merger, also addressed Met-Ed's and Penelec's request for
PLR rate relief. Met-Ed and Penelec are permitted to defer, for future recovery,
the difference between their actual energy costs and those reflected in their
capped generation rates. Those costs will continue to be deferred through
December 31, 2005. If energy costs incurred by Met-Ed and Penelec during that
period are below their respective capped generation rates, the difference would
be used to reduce their recoverable deferred costs. Met-Ed's and Penelec's PLR
obligations were extended through December 31, 2010. Met-Ed's and Penelec's CTC
revenues will be applied first to PLR costs, then to stranded costs other than
for non-utility generation (NUG) and finally to NUG stranded costs through
December 31, 2010. Met-Ed and Penelec would be permitted to recover any
remaining stranded costs through a continuation of the CTC, after December 31,
2010, however, such recovery would extend to no later than December 31, 2015.
Any amounts not expected to be recovered by December 31, 2015 would be written
off at the time such nonrecovery becomes probable. Several parties had appealed
this PPUC decision to the Commonwealth Court of Pennsylvania. On February 21,
2002, the Court affirmed the PPUC decision regarding approval of the GPU merger,
remanding the decision to the PPUC only with respect to the issue of merger
savings. The Court reversed the PPUC's decision regarding the PLR obligations of
Met-Ed and Penelec, and denied the related requests for rate relief by Met-Ed
and Penelec. We are considering our response to the Court's decision, which
could include asking the Pennsylvania Supreme Court to review the decision. We
are unable to predict the outcome of these matters.
New Jersey -
Customers of JCP&L were able to choose among alternative energy
suppliers beginning in late 1999. To support customer choice, rates were
restructured into unbundled service charges and additional non-bypassable
charges to recover stranded costs (confirmed by a NJBPU Final Decision and Order
issued in March 2001). JCP&L has a PLR obligation, referred to as Basic
Generation Service (BGS), until July 31, 2002. For the period from August 1,
2002 to July 31, 2003, the NJBPU has authorized the auctioning of BGS to meet
the electric demands of customers who have not selected an alternative supplier.
The auction was successfully concluded on February 13, 2002, thereby eliminating
JCP&L's obligation to provide for the energy requirements of BGS during that
period. Beginning August 1, 2003, the approach to be taken in procuring the
energy needs for BGS has not been determined. The NJBPU recently initiated a
formal proceeding to decide how BGS will be handled after the transition period.
JCP&L is permitted to defer, for future recovery, the amount by which its
reasonable and prudently incurred costs for providing BGS to non-shopping
customers and costs incurred under NUG agreements exceed amounts currently
reflected in its BGS rate and market transition charge rate (for the recovery of
stranded costs).
On September 26, 2001, the NJBPU approved the GPU merger subject to
the terms and conditions set forth in a settlement agreement with major
intervenors. As part of the settlement, we agreed to reduce JCP&L's costs
deferred for future recovery by $300 million, in order to ensure that customers
receive the benefit of future merger savings. JCP&L wrote off $300 million of
its deferred costs in October 2001 upon receipt of the final regulatory approval
for the merger, which occurred on October 29, 2001.
On February 6, 2002, JCP&L received a Financing Order from the NJBPU
with authorization to issue $320 million of transition bonds to securitize the
recovery of bondable stranded costs associated with the previously divested
Oyster Creek nuclear generating station. The Order grants JCP&L the right to
charge a usage-based, non-bypassable transition bond charge (TBC) and provide
for the transfer of the bondable transition property relating to the TBC to
JCP&L Transition Funding LLC (Transition Funding), a wholly owned limited
liability corporation. Transition Funding is expected to issue and sell up to
$320 million of transition bonds that will be recognized on our Consolidated
Balance Sheet in the second quarter of 2002, with the TBC providing recovery of
principal, interest and related fees on the transition bonds.
FERC Regulatory Matters
On December 19, 2001, the Federal Energy Regulatory Commission (FERC)
issued an order in which it stated that the Alliance Regional Transmission
Organization (Alliance TransCo) did not meet agency requirements to operate the
Alliance TransCo as an approved Regional Transmission Organization (RTO). It
further concluded that National Grid could be the independent Managing Member of
the Alliance TransCo. FERC ordered the Alliance TransCo and National Grid to
refile their business plan to consider operating as an independent transmission
company within the
Midwest ISO or another RTO. The order gave the Alliance TransCo 60 days to file
a status report. On January 22, 2002, the Alliance TransCo companies filed a
series of rehearing applications with FERC.
Supply Plan
As part of the Restructuring Orders for the States of Ohio,
Pennsylvania, and New Jersey, the FirstEnergy companies are obligated to supply
electricity to customers who do not choose an alternate supplier. The total
forecasted peak of this obligation in 2002 is 20,300 MW (10,100 MW in Ohio,
5,400 MW in New Jersey, and 4,800 MW in Pennsylvania). The successful BGS
auction in New Jersey removed JCP&L's BGS obligation for 5,100 MW for the period
from August 1, 2002 to July 31, 2003. In that auction FES was a successful
bidder to provide 1,700 MW during the same period to JCP&L and two other
electric utilities in New Jersey. Our current supply portfolio contains 13,283
MW of owned generation and approximately 1,600 MW of long-term purchases from
non-utility generators. The remaining obligation is expected to be met through a
mix of multi-year forward purchases, short-term forward (less than one year)
purchases and spot market purchases.
The announced sale of four fossil generating plants expected to close
in mid-2002, will have little impact on our supply plan. As part of the asset
sale, FirstEnergy has a power purchase agreement under which the purchaser will
provide a similar amount of electricity as was expected before the sale. This
power purchase agreement runs from the close of the sale transaction, through
December 31, 2005, which is the end of the market development period for the
Ohio operating companies.
Unregulated retail sales are generally short-term arrangements (less
than 18 months) at prevailing market prices. They are primarily hedged through
short-term purchased power contracts, supplemented by any of our excess
generation when available and economical.
Environmental Matters
We are in compliance with the current sulfur dioxide (SO2) and
nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 6 - Environmental
Matters). We continue to evaluate our compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $27,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W.H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn. The NOV and complaint allege violations of the Clean Air
Act (CAA). The civil complaint against OE and Penn requests installation of
"best available control technology" as well as civil penalties of up to $27,500
per day. Although unable to predict the outcome of these proceedings, we believe
the Sammis Plant is in full compliance with the CAA and that 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. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
Various environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2001, based on estimates of the
total costs of cleanup, the Companies' proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. The
Companies 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. In addition, JCP&L has accrued liabilities for
environmental remediation of former manufactured gas plants in New Jersey; those
costs are being recovered by JCP&L through a non-bypassable societal benefits
charge. The Companies have total accrued liabilities aggregating approximately
$60 million as of December 31, 2001. We do not believe environmental remediation
costs will have a material adverse effect on financial condition, cash flows or
results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant are described below.
Due to our merger with GPU, we own Unit 2 of the Three Mile Island
(TMI-2) Nuclear Plant. As a result of the 1979 TMI-2 accident, claims for
alleged personal injury against JCP&L, Met-Ed, Penelec and GPU were filed in the
U.S. District Court for the Middle District of Pennsylvania. In 1996, the
District Court granted a motion for summary judgment filed by the GPU companies
and dismissed the ten initial "test cases" which had been selected for a test
case trial, as well as all of the remaining 2,100 pending claims. In November
1999, the U.S. Court of Appeals for the Third Circuit affirmed the District
Court's dismissal of the ten test cases, but set aside the dismissal of the
additional pending claims, remanding them to the District Court for further
proceedings. Following the resolution of judicial proceedings dealing with
admissible evidence, we have again requested summary judgment of the remaining
2,100 claims in the District Court. On January 15, 2002, the District Court
granted our motion. On February 14, 2002, the plaintiffs filed a notice of
appeal of this decision (see Note 6 - Other Legal Proceedings). Although unable
to predict the outcome of this litigation, we believe that any liability to
which we might be subject by reason of the TMI-2 accident will not exceed our
financial protection under the Price-Anderson Act.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service areas of many electric
utilities, including JCP&L. In an investigation into the causes of the outages
and the reliability of the transmission and distribution systems of all four New
Jersey electric utilities, the NJBPU concluded that there was not a prima facie
case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper
service to its customers. Two class action lawsuits (subsequently consolidated
into a single proceeding) were filed in New Jersey Superior Court in July 1999
against JCP&L, GPU and other GPU companies seeking compensatory and punitive
damages arising from the service interruptions of July 1999 in the JCP&L
territory. In May 2001, the court denied without prejudice the defendant's
motion seeking decertification of the class. Discovery continues in the class
action, but no trial date has been set. The judge has set a schedule under which
factual legal discovery would conclude in March 2002, and expert reports would
be exchanged by June 2002. In October 2001, the court held argument on the
plaintiffs' motion for partial summary judgment, which contends that JCP&L is
bound to several findings of the NJBPU investigation. The plaintiffs' motion was
denied by the Court in November 2001 and the plaintiffs' motion seeking
permission to file an appeal on this denial of their motion was rejected by the
New Jersey Appellate Division. We have also filed a motion for partial summary
judgment that is currently pending before the Superior Court. We are unable to
predict the outcome of these matters.
Other Commitments, Guarantees and Contingencies
GPU had made significant investments in foreign businesses and
facilities through its GPU Electric and GPU Power subsidiaries. Although we will
attempt to mitigate our risks related to foreign investments, we face additional
risks inherent in operating in such locations, including foreign currency
fluctuations.
GPU Electric, through its subsidiary, Midlands, has a 40% equity
interest in a 586 MW power project in Pakistan (the Uch Power Project), which
commenced commercial operations in October 2000. GPU Electric's investment in
this project as of December 31, 2001 was approximately $38 million, plus a
guaranty letter of credit of $3.6 million, and its share of the projected
completion costs represents an additional $4.8 million commitment. Cinergy (the
former owner of 50% of Midlands Electricity plc) agreed to fund up to an
aggregate of $20 million of the required capital contributions and has
reimbursed GPU Electric $4.9 million through December 31, 2001, leaving a
remaining commitment for future cash losses of up to $15.1 million. Midlands
also has a 31% equity interest in a 478 MW power project in Turkey (the Trakya
Power Project). Trakya is presently engaged in a foreign currency conversion
issue with TETTAS (the state owned electricity purchaser). Midlands established
a $16.5 million reserve for non-recovery relating to that issue as of December
31, 2001. These commitments and contingencies associated with Midlands will
transfer to the new partnership upon completion of the sale discussed in Note 2
- - Merger, and we will be responsible for our lower proportionate interest.
El Barranquilla, a wholly owned subsidiary of GPU Power, is an equity
investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which
owns a Colombian independent power generation project. As of December 31, 2001,
GPU Power had an investment of approximately $109.4 million in TEBSA and is
committed, under certain circumstances, to make additional standby equity
contributions of $21.3 million, which we have guaranteed. The total outstanding
senior debt of the TEBSA project is $315 million at December 31, 2001. The
lenders include the
Overseas Private Investment Corporation, US Export Import Bank and a commercial
bank syndicate. GPU had guaranteed the obligations of the operators of the TEBSA
project, up to a maximum of $5.8 million (subject to escalation) under the
project's operations and maintenance agreement.
GPU believed that various events of default have occurred under the
loan agreements relating to the TEBSA project. In addition, questions have been
raised as to the accuracy and completeness of information provided to various
parties to the project in connection with the project's formation. We continue
to discuss these issues and related matters with the project lenders, CORELCA
(the government owned Colombian electric utility with an ownership interest in
the project) and the Government of Colombia.
Moreover, in September 2001, the DIAN (the Colombian national tax
authority) had presented TEBSA with a statement of charges alleging that certain
lease payments made under the Lease Agreement with Los Amigos Leasing Company
(an indirect wholly owned subsidiary of GPU Power) violated Colombian foreign
exchange regulations and were, therefore, subject to substantial penalties. The
DIAN has calculated a statutory penalty amounting to approximately $200 million
and gave TEBSA two months to respond to the statement of charges. In November
2001, TEBSA filed a formal response to this statement of charges. TEBSA is
continuing to review the DIAN's position and has been advised by its Colombian
counsel that the DIAN's position is without substantial legal merit. We are
unable to predict the outcome of these matters.
Significant Accounting Policies
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often require a high degree of judgment, estimates and
assumptions that affect our financial results. All of our assets are subject to
their own specific risks and uncertainties and are continually reviewed for
impairment. Assets related to the application of the policies discussed below
are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below:
Purchase Accounting - Acquisition of GPU
Purchase accounting requires judgment regarding the allocation of the
purchase price based on the fair values of the assets acquired (including
intangible assets) and the liabilities assumed. The fair values of the acquired
assets and assumed liabilities for GPU were based primarily on estimates. The
more significant of these included the estimation of the fair value of the
international operations, certain domestic operations and the fair value of the
pension and other postretirement benefit assets and liabilities. The preliminary
purchase price allocations for the GPU acquisition are subject to adjustment in
2002 when finalized. The excess of the purchase price over the estimated fair
values of the assets acquired and liabilities assumed was recognized as
goodwill, which will be reviewed for impairment at least annually. As of
December 31, 2001, we had $5.6 billion of goodwill (excluding the goodwill in
"Assets Pending Sale" on the Consolidated Balance Sheet) that primarily relates
to our regulated services segment.
Regulatory Accounting
Our regulated services segment is subject to regulation that sets the
prices (rates) we are permitted to charge our customers based on our costs that
the regulatory agencies determine we are permitted to recover. At times,
regulators permit the future recovery through rates of costs that would be
currently charged to expense by an unregulated company. This rate-making process
results in the recording of regulatory assets based on anticipated future cash
inflows. As a result of the changing regulatory framework in each state in which
we operate, a significant amount of regulatory assets have been recorded. As of
December 31, 2001, we had regulatory assets of $8.9 billion. We continually
review these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
As disclosed in Note 1 - Regulatory Plans, the full recovery of transition costs
for the Ohio EUOC is dependent on achieving 20% customer shopping levels in any
twelve-month period by December 31, 2005.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions must
be documented. Derivative contracts that are determined to fall within the scope
of SFAS 133, as amended, must be recorded at their fair value. Active market
prices are not always available to determine the fair value of the later years
of a contract, requiring that various assumptions and estimates be used in the
valuation. We continually monitor our
derivative contracts to determine if our activities, expectations, intentions,
assumptions and estimates remain valid. As part of our normal operations we
enter into significant commodities contracts, which increase the impact of
derivative accounting judgments.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hour sales that have been delivered but not yet been billed
through the end of the year. The determination of unbilled revenues requires
management to make various estimated including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o Mix of kilowatt-hour usage by residential, commercial and
industrial customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Recently Issued Accounting Standards
The Financial Accounting Standards Board (FASB) approved SFAS 141,
"Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on
June 29, 2001. SFAS 141 requires all business combinations initiated after June
30, 2001, to be accounted for using purchase accounting. The provisions of the
new standard relating to the determination of goodwill and other intangible
assets have been applied to the GPU merger, which was accounted for as a
purchase transaction, and have not materially affected the accounting for this
transaction. Under SFAS 142, amortization of existing goodwill will cease
January 1, 2002. Instead, goodwill will be tested for impairment at least on an
annual basis, and no impairment of goodwill is anticipated as a result of a
preliminary analysis. Prior to the GPU merger, FirstEnergy amortized about $57
million ($.25 per share of common stock) of goodwill annually. There was no
goodwill amortization in 2001 associated with the GPU merger under the
provisions of the new standard.
In July 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations." The new statement provides accounting standards for
retirement obligations associated with tangible long-lived assets, with adoption
required by January 1, 2003. SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recorded in the period in which
it is incurred. The associated asset retirement costs are capitalized as part of
the carrying amount of the long-lived asset. Over time the capitalized costs are
depreciated and the present value of the asset retirement liability increases,
resulting in a period expense. Upon retirement, a gain or loss will be recorded
if the cost to settle the retirement obligation differs from the carrying
amount. We are currently assessing the new standard and have not yet determined
the impact on our financial statements.
In September 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The Statement also supersedes the accounting and reporting
provisions of APB 30. Our adoption of this Statement, effective January 1, 2002,
will result in our accounting for any future impairments or disposals of
long-lived assets under the provisions of SFAS 144, but will not change the
accounting principles used in previous asset impairments or disposals.
Application of SFAS 144 is not anticipated to have a major impact on accounting
for impairments or disposal transactions compared to the prior application of
SFAS 121 or APB 30.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
REVENUES:
Electric utilities.................................................... $5,729,036 $5,421,668 $5,453,763
Unregulated businesses................................................ 2,270,326 1,607,293 865,884
---------- ---------- ----------
Total revenues.................................................... 7,999,362 7,028,961 6,319,647
---------- ---------- ----------
EXPENSES:
Fuel and purchased power.............................................. 1,421,525 1,110,845 984,941
Purchased gas......................................................... 820,031 553,548 170,630
Other operating expenses.............................................. 2,727,794 2,378,296 2,146,629
Provision for depreciation and amortization........................... 889,550 933,684 937,976
General taxes......................................................... 455,340 547,681 544,052
---------- ---------- ----------
Total expenses.................................................... 6,314,240 5,524,054 4,784,228
---------- ---------- ----------
INCOME BEFORE INTEREST AND INCOME TAXES.................................. 1,685,122 1,504,907 1,535,419
---------- ---------- ----------
NET INTEREST CHARGES:
Interest expense...................................................... 519,131 493,473 509,169
Capitalized interest.................................................. (35,473) (27,059) (13,355)
Subsidiaries' preferred stock dividends............................... 72,061 62,721 76,479
---------- ---------- ----------
Net interest charges.............................................. 555,719 529,135 572,293
---------- ---------- ----------
INCOME TAXES............................................................. 474,457 376,802 394,827
---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE
IN ACCOUNTING......................................................... 654,946 598,970 568,299
---------- ---------- ----------
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF
INCOME TAX BENEFIT OF $5,839,000) (Note 1)............................ (8,499) -- --
---------- ---------- ----------
NET INCOME............................................................... $ 646,447 $ 598,970 $ 568,299
========== ========== ==========
BASIC EARNINGS PER SHARE OF COMMON STOCK (Note 4C):
Income before cumulative effect of accounting change.................. $2.85 $2.69 $2.50
Cumulative effect of accounting change (Net of income taxes) (Note 1). (.03) -- --
----- ----- -----
Net income............................................................ $2.82 $2.69 $2.50
===== ===== =====
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING................... 229,512 222,444 227,227
======= ======= =======
DILUTED EARNINGS PER SHARE OF COMMON STOCK (Note 4C):
Income before cumulative effect of accounting change.................. $2.84 $2.69 $2.50
Cumulative effect of accounting change (Net of income taxes) (Note 1). (.03) -- --
----- ----- -----
Net income............................................................ $2.81 $2.69 $2.50
===== ===== =====
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING................. 230,430 222,726 227,299
======= ======= =======
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.
</FN>
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
As of December 31, 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.......................................................... $ 220,178 $ 49,258
Receivables-
Customers (less accumulated provisions of $65,358,000 and $32,251,000,
respectively, for uncollectible accounts)...................................... 1,074,664 541,924
Other (less accumulated provisions of $7,947,000 and $4,035,000,
respectively, for uncollectible accounts)...................................... 473,550 376,525
Materials and supplies, at average cost-
Owned............................................................................ 256,516 171,563
Under consignment................................................................ 141,002 112,155
Prepayments and other.............................................................. 336,610 189,869
----------- -----------
2,502,520 1,441,294
----------- -----------
ASSETS PENDING SALE (Note 2)......................................................... 3,418,225 --
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service......................................................................... 19,981,749 12,417,684
Less--Accumulated provision for depreciation....................................... 8,161,022 5,263,483
----------- -----------
11,820,727 7,154,201
Construction work in progress...................................................... 607,702 420,875
----------- -----------
12,428,429 7,575,076
----------- -----------
INVESTMENTS:
Capital trust investments (Note 3)................................................. 1,166,714 1,223,794
Nuclear plant decommissioning trusts............................................... 1,014,234 584,288
Letter of credit collateralization (Note 3)........................................ 277,763 277,763
Pension investments................................................................ 273,542 200,178
Other.............................................................................. 898,311 468,879
----------- -----------
3,630,564 2,754,902
----------- -----------
DEFERRED CHARGES:
Regulatory assets.................................................................. 8,912,584 3,727,662
Goodwill........................................................................... 5,600,918 2,088,770
Other.............................................................................. 858,273 353,590
----------- -----------
15,371,775 6,170,022
----------- -----------
$37,351,513 $17,941,294
=========== ===========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock............................... $ 1,867,657 $ 536,482
Short-term borrowings (Note 5)..................................................... 614,298 699,765
Accounts payable................................................................... 704,184 478,661
Accrued taxes...................................................................... 418,555 409,640
Other.............................................................................. 1,064,763 469,257
----------- -----------
4,669,457 2,593,805
----------- -----------
LIABILITIES RELATED TO ASSETS PENDING SALE (Note 2).................................. 2,954,753 --
----------- -----------
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders' equity........................................................ 7,398,599 4,653,126
Preferred stock of consolidated subsidiaries--
Not subject to mandatory redemption.............................................. 480,194 648,395
Subject to mandatory redemption.................................................. 65,406 41,105
Subsidiary-obligated mandatorily redeemable preferred securities (Note 4F)......... 529,450 120,000
Long-term debt..................................................................... 11,433,313 5,742,048
----------- -----------
19,906,962 11,204,674
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes.................................................. 2,684,219 2,094,107
Accumulated deferred investment tax credits........................................ 260,532 241,005
Nuclear plant decommissioning costs................................................ 1,201,599 598,985
Power purchase contract loss liability............................................. 3,566,531 --
Other postretirement benefits...................................................... 838,943 544,541
Other.............................................................................. 1,268,517 664,177
----------- -----------
9,820,341 4,142,815
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 3 and 6).............................
----------- -----------
$37,351,513 $17,941,294
=========== ===========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
</FN>
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $0.10 par value - authorized 375,000,000 shares-
297,636,276 and 224,531,580 shares outstanding, respectively......................... $ 29,764 $ 22,453
Other paid-in capital.................................................................. 6,113,260 3,531,821
Accumulated other comprehensive income (loss) (Note 4H)................................ (169,003) 593
Retained earnings (Note 4A)............................................................ 1,521,805 1,209,991
Unallocated employee stock ownership plan common stock-
5,117,375 and 5,952,032 shares, respectively (Note 4B)............................... (97,227) (111,732)
----------- -----------
Total common stockholders' equity.................................................... 7,398,599 4,653,126
----------- -----------
Number of Shares Optional
Outstanding Redemption Price
---------------- ---------------------
2001 2000 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Note 4D):
Ohio Edison Company
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:
8.45%.............................. -- 50,000 -- $ -- -- 5,000
Redemption Within One Year........... -- (5,000)
--------- --------- -------- ----------- -----------
Total Subject to Mandatory Redemption -- 50,000 $ -- -- --
========= ========= ======== ----------- -----------
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 (Note 4E):
7.625%............................. 150,000 150,000 104.58 $ 15,687 15,000 15,000
Redemption Within One Year........... (750) --
--------- --------- -------- ----------- -----------
Total Subject to Mandatory Redemption 150,000 150,000 $ 15,687 14,250 15,000
========= ========= ======== ----------- -----------
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
--------- --------- -------- ----------- -----------
1,624,000 1,624,000 243,917 238,325 238,325
Redemption Within One Year (Note 4D). (96,850) --
--------- --------- -------- ----------- -----------
Total Not Subject to Mandatory
Redemption......................... 1,624,000 1,624,000 $243,917 141,475 238,325
========= ========= ======== ----------- -----------
Subject to Mandatory Redemption (Note 4E):
$ 7.35 Series C................... 70,000 80,000 101.00 $ 7,070 7,030 8,041
$91.50 Series Q.................... -- 10,716 -- -- -- 10,716
$88.00 Series R.................... -- 50,000 -- -- -- 51,128
$90.00 Series S.................... 17,750 36,500 -- -- 17,268 36,686
--------- --------- -------- ----------- -----------
87,750 177,216 7,070 24,298 106,571
Redemption Within One Year........... (18,010) (80,466)
--------- --------- -------- ----------- -----------
Total Subject to Mandatory Redemption 87,750 177,216 $ 7,070 6,288 26,105
========= ========= ======== ----------- -----------
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
Number of Shares Optional
Outstanding Redemption Price
---------------- ---------------------
2001 2000 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Cont'd)
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
Redemption Within One Year (Note 4D). (59,000) --
--------- --------- -------- ----------- -----------
900,000 900,000 92,040 31,000 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
--------- --------- --------
Redemption Within One Year (Note 4D). (25,000) --
--------- --------- -------- ----------- -----------
4,800,000 4,800,000 124,100 95,000 120,000
--------- --------- -------- ----------- -----------
Total Not Subject to Mandatory
Redemption....................... 5,700,000 5,700,000 $216,140 126,000 210,000
========= ========= ======== ----------- -----------
Jersey Central Power & Light Company
Cumulative, $100 stated value-
Authorized 15,600,000 shares
Not Subject to Mandatory Redemption:
4.00% Series....................... 125,000 -- 106.50 $ 13,313 12,649 --
========= ========= ======== ----------- -----------
Subject to Mandatory Redemption (Note 4E):
8.65% Series J..................... 250,001 -- 101.30 $ 25,325 26,750 --
7.52% Series K..................... 265,000 -- 103.76 27,496 28,951 --
--------- --------- -------- ----------- -----------
515,001 -- 52,821 55,701 --
Redemption Within One Year........... (10,833) --
--------- --------- -------- ----------- -----------
Total Subject to Mandatory Redemption 515,001 -- $ 52,821 44,868 --
========= ========= ======== ----------- -----------
SUBSIDIARY-OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST OR LIMITED PARTNERSHIP
HOLDING SOLELY SUBORDINATED DEBENTURES
OF SUBSIDIARIES (NOTE 4F):
Ohio Edison Co.
Cumulative, $25 stated value-
Authorized 4,800,000 shares
9.00%................................ 4,800,000 4,800,000 25.00 $120,000 120,000 120,000
========= ========= ======== ----------- -----------
Cleveland Electric Illuminating Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
9.00%................................ 4,000,000 -- -- $ -- 100,000 --
========= ========= ======== ----------- -----------
Jersey Central Power & Light Co.
Cumulative, $25 stated value-
Authorized 5,000,000 shares
8.56%................................ 5,000,000 -- 25.00 $125,000 125,250 --
========= ========== ======== ----------- -----------
Metropolitan Edison Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
7.35%................................ 4,000,000 -- -- $ -- 92,200 --
========= ========= ======== ----------- -----------
Pennsylvania Electric Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
7.34%................................ 4,000,000 -- -- $ -- 92,000 --
========= ========= ======== ----------- -----------
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, 2001 2000 2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ---- ---- ----
Ohio Edison Co. -
Due 2001-2006 7.89% $ 509,265 $ 509,265 7.60% $ 227,122 $ 235,838 4.28% $ 441,725 $541,725
Due 2007-2011 -- -- -- 7.22% 10,253 4,336 -- -- --
Due 2012-2016 -- -- -- 5.17% 59,000 59,000 -- -- --
Due 2017-2021 -- -- -- 7.01% 60,443 129,943 -- -- --
Due 2022-2026 7.99% 219,460 219,460 -- -- -- -- -- --
Due 2027-2031 -- -- -- 3.72% 249,634 180,134 -- -- --
Due 2032-2036 -- -- -- 2.63% 71,900 71,900 -- -- --
---------- ---------- ---------- ---------- ---------- --------
Total-Ohio Edison 728,725 728,725 678,352 681,151 441,725 541,725 $ 1,848,802 $ 1,951,601
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Cleveland Electric
Illuminating Co. -
Due 2001-2006 8.53% 595,000 595,000 5.84% 593,175 384,680 5.58% 27,700 27,700
Due 2007-2011 6.86% 125,000 125,000 7.29% 271,640 271,640 -- -- --
Due 2012-2016 -- -- -- 8.00% 78,700 118,535 -- -- --
Due 2017-2021 -- -- -- 7.36% 440,560 560,855 -- -- --
Due 2022-2026 9.00% 150,000 150,000 7.64% 218,950 218,950 -- -- --
Due 2027-2031 -- -- -- 5.38% 5,993 110,888 -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Cleveland Electric 870,000 870,000 1,609,018 1,665,548 27,700 27,700 2,506,718 2,563,248
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Toledo Edison Co. -
Due 2001-2006 7.90% 179,125 179,525 6.40% 228,700 190,400 7.25% 226,100 226,130
Due 2007-2011 -- -- -- 7.13% 30,000 30,000 10.00% 790 790
Due 2012-2016 -- -- -- -- -- -- -- -- --
Due 2017-2021 -- -- -- 8.14% 129,000 129,000 -- -- --
Due 2022-2026 -- -- -- 7.55% 50,700 118,000 -- -- --
Due 2027-2031 -- -- -- 5.90% 13,851 13,851 -- -- --
Due 2032-2036 -- -- -- 2.20% 30,900 30,900 -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Toledo Edison 179,125 179,525 483,151 512,151 226,890 226,920 889,166 918,596
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Pennsylvania Power Co. -
Due 2001-2006 7.19% 79,370 80,344 3.02% 10,300 -- 5.90% 5,200 5,200
Due 2007-2011 9.74% 4,870 4,870 -- -- -- -- -- --
Due 2012-2016 9.74% 4,870 4,870 5.40% 1,000 1,000 -- -- --
Due 2017-2021 9.74% 2,955 2,955 3.78% 59,807 59,807 -- -- --
Due 2022-2026 8.33% 33,750 33,750 6.15% 12,700 12,700 -- -- --
Due 2027-2031 -- -- -- 6.04% 37,672 47,972 -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Penn Power 125,815 126,789 121,479 121,479 5,200 5,200 252,494 253,468
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Jersey Central Power & Light Co. -
Due 2001-2006 7.14% 500,945 -- 6.45% 150,000 -- 7.69% 86 --
Due 2007-2011 7.81% 45,355 -- -- -- -- 7.69% 124 --
Due 2012-2016 7.10% 12,200 -- -- -- -- 7.69% 180 --
Due 2017-2021 9.20% 50,000 -- -- -- -- 7.69% 260 --
Due 2022-2026 7.68% 485,000 -- -- -- -- 7.69% 377 --
Due 2027-2031 -- -- -- -- -- -- 7.69% 546 --
Due 2032-2036 -- -- -- -- -- -- 7.69% 790 --
Due 2037-2041 -- -- -- -- -- -- 7.69% 635 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Jersey Central 1,093,500 -- 150,000 -- 2,998 -- 1,246,498 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Metropolitan Edison Co. -
Due 2001-2006 7.14% 261,740 -- 5.72% 100,000 -- 7.69% 171 --
Due 2007-2011 6.00% 6,960 -- -- -- -- 7.69% 248 --
Due 2012-2016 -- -- -- -- -- -- 7.69% 359 --
Due 2017-2021 6.10% 28,500 -- -- -- -- 7.69% 521 --
Due 2022-2026 8.05% 180,000 -- -- -- -- 7.69% 754 --
Due 2027-2031 5.95% 13,690 -- -- -- -- 7.69% 1,092 --
Due 2032-2036 -- -- -- -- -- -- 7.69% 1,581 --
Due 2037-2041 -- -- -- -- -- -- 7.69% 1,271 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Metropolitan Edison 490,890 -- 100,000 -- 5,997 -- 596,887 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (Interest rates reflect weighted average rates) (Cont'd) (In thousands)
FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL
- ----------------------------------------------------------------------------------------------------------------------------------
As of December 31, 2001 2000 2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ---- ---- ----
Pennsylvania
Electric Co. -
Due 2001-2006 6.13% $ 1,025 $ -- -- $ -- $ -- 6.02% $ 183,086 $ --
Due 2007-2011 5.44% 27,395 -- -- -- -- 6.55% 135,124 --
Due 2012-2016 -- -- -- -- -- -- 7.69% 180 --
Due 2017-2021 5.80% 20,000 -- -- -- -- 6.63% 125,260 --
Due 2022-2026 6.05% 25,000 -- -- -- -- 7.69% 377 --
Due 2027-2031 -- -- -- -- -- -- 7.69% 546 --
Due 2032-2036 -- -- -- -- -- -- 7.69% 790 --
Due 2037-2041 -- -- -- -- -- -- 7.69% 635 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Pennsylvania
Electric 73,420 -- -- -- 445,998 -- $ 519,418 $ --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
FirstEnergy Corp. -
Due 2001-2006 -- -- -- -- -- -- 5.59% 1,550,000 --
Due 2007-2011 -- -- -- -- -- -- 6.45% 1,500,000 --
Due 2012-2016 -- -- -- -- -- -- -- -- --
Due 2017-2021 -- -- -- -- -- -- -- -- --
Due 2022-2026 -- -- -- -- -- -- -- -- --
Due 2027-2031 -- -- -- -- -- -- 7.38% 1,500,000 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-FirstEnergy -- -- -- -- 4,550,000 -- 4,550,000 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
OES Fuel -- -- 2.72% 81,515 91,620 -- -- -- 81,515 91,620
AFN Finance Co. No. 1 -- -- 4.18% 15,000 -- -- -- -- 15,000 --
AFN Finance Co. No. 3 -- -- 4.18% 4,000 -- -- -- -- 4,000 --
Bay Shore Power -- -- 6.23% 145,400 147,500 -- -- -- 145,400 147,500
MARBEL Energy Corp. -- -- -- -- -- 4.72% 569 638 569 638
Facilities Services Group -- -- 6.12% 15,735 17,601 -- -- -- 15,735 17,601
FirstEnergy Properties -- -- 7.89% 9,902 -- -- -- -- 9,902 --
Warrenton River Terminal -- -- 6.00% 776 -- -- -- -- 776 --
GPU Capital* -- -- -- -- -- 6.69% 1,629,582 -- 1,629,582 --
GPU Power -- -- 7.42% 239,373 -- 13.50% 56,048 -- 295,421 --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total $3,561,475 $1,905,039 $3,653,701 $3,237,050 $7,392,707 $802,183 14,607,883 5,944,272
========== ========== ========== ========== ========== ======== ----------- -----------
Capital lease obligations..................................................................... 19,390 163,242
----------- -----------
Net unamortized premium on debt*.............................................................. 213,834 85,550
----------- -----------
Long-term debt due within one year*.......................................................... (1,975,755) (451,016)
----------- -----------
Total long-term debt*......................................................................... 12,865,352 5,742,048
----------- -----------
TOTAL CAPITALIZATION* $21,339,001 $11,204,674
- ----------------------------------------------------------------------------------------------------------------------------------
<FN>
* 2001 includes amounts in "Liabilities Related to Assets Pending Sale" on the
Consolidated Balance Sheet as of December 31, 2001.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
</FN>
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, 1999............ 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 in
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)
GPU acquisition.................. 73,654,696 7,366 2,586,097
Net income....................... $646,447 646,447
Minimum liability for unfunded
retirement benefits, net of
$(182,000) of income taxes.... (268) (268)
Unrealized loss on derivative hedges,
net of $(116,521,000) of income
taxes (169,408) (169,408)
Unrealized gain on investments, net
of $56,000 of income taxes..... 81 81
Unrealized currency translation
adjustments, net of $(1,000) of
income taxes (1) (1)
--------
Comprehensive income............. $476,851
========
Reacquired common stock.......... (550,000) (55) (15,253)
Allocation of ESOP shares........ 10,595 14,505
Cash dividends on common stock... (334,633)
- --------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001.......... 297,636,276 $29,764 $6,113,260 $(169,003) $1,521,805 $(97,227)
==========================================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
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, 1999 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
GPU acquisition 125,000 12,649 13,515,001 365,151
Issues-
9.00% Series 4,000,000 100,000
Redemptions-
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series R (50,000) (50,000)
$91.50 Series Q (10,716) (10,716)
$90.00 Series S (18,750) (18,750)
Amortization of fair market
value adjustments-
$ 7.35 Series C (11)
$88.00 Series R (1,128)
$90.00 Series S (668)
-----------------------------------------------------------------------------------
Balance, December 31, 2001 12,449,699 $661,044 22,552,751 $624,449
===================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
</FN>
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...................................................... $ 646,447 $ 598,970 $ 568,299
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization................ 889,550 933,684 937,976
Nuclear fuel and lease amortization........................ 98,178 113,330 104,928
Other amortization, net.................................... (11,927) (11,635) (10,730)
Deferred costs recoverable as regulatory assets............ (31,893) -- --
Deferred income taxes, net................................. 31,625 (79,429) (45,054)
Investment tax credits, net................................ (22,545) (30,732) (19,661)
Cumulative effect of accounting change..................... 14,338 -- --
Receivables................................................ 53,099 (150,520) (203,567)
Materials and supplies..................................... (50,052) (29,653) 19,631
Accounts payable........................................... (84,572) 118,282 82,578
Other...................................................... (250,564) 45,529 53,906
---------- ---------- ----------
Net cash provided from operating activities.............. 1,281,684 1,507,826 1,488,306
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Preferred stock.............................................. 96,739 -- --
Long-term debt............................................... 4,338,080 307,512 364,832
Short-term borrowings, net................................... -- 281,946 163,327
Redemptions and Repayments-
Common stock................................................. 15,308 195,002 130,133
Preferred stock.............................................. 85,466 38,464 52,159
Long-term debt............................................... 394,017 901,764 847,006
Short-term borrowings, net................................... 1,641,484 -- --
Common Stock Dividend Payments.................................. 334,633 334,220 341,467
---------- ---------- ----------
Net cash provided from (used for) financing activities... 1,963,911 (879,992) (842,606)
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
GPU acquisition, net of cash.................................... 2,013,218 -- --
Property additions.............................................. 852,449 587,618 624,901
Cash investments................................................ (24,518) (17,449) (41,213)
Other........................................................... 233,526 120,195 28,022
---------- ---------- ----------
Net cash used for investing activities................... 3,074,675 690,364 611,710
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents............ 170,920 (62,530) 33,990
Cash and cash equivalents at beginning of year.................. 49,258 111,788 77,798
---------- ---------- ----------
Cash and cash equivalents at end of year*....................... $ 220,178 $ 49,258 $ 111,788
========== ========== ==========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................ $ 425,737 $ 485,374 $ 520,072
Income taxes................................................. $ 433,640 $ 512,182 $ 441,067
<FN>
* 2001 excludes amounts in "Assets Pending Sale" in the Consolidated Balance
Sheet as of December 31, 2001.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
</FN>
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property........................................... $ 176,916 $ 281,374 $ 276,227
State gross receipts................................................. 102,335 221,385 220,117
Ohio kilowatt-hour excise............................................ 117,979 -- --
Social security and unemployment..................................... 44,480 39,134 37,019
Other................................................................ 13,630 5,788 10,689
---------- ---------- ----------
Total general taxes........................................... $ 455,340 $ 547,681 $ 544,052
========== ========== ==========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal........................................................... $ 375,108 $ 467,045 $ 433,872
State............................................................. 84,322 19,918 25,670
Foreign........................................................... 108 -- --
---------- ---------- ----------
459,538 486,963 459,542
---------- ---------- ----------
Deferred, net-
Federal........................................................... 37,888 (60,831) (36,021)
State............................................................. (6,177) (18,598) (9,033)
Foreign........................................................... (86) -- --
---------- ---------- ----------
31,625 (79,429) (45,054)
---------- ---------- ----------
Investment tax credit amortization................................... (22,545) (30,732) (19,661)
---------- ---------- ----------
Total provision for income taxes.............................. $ 468,618 $ 376,802 $ 394,827
========== ========== ==========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes........................ $1,115,065 $ 975,772 $ 963,126
========== ========== ==========
Federal income tax expense at statutory rate......................... $ 390,273 $ 341,520 $ 337,094
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits............................ (22,545) (30,732) (19,661)
State income taxes, net of federal income tax benefit............. 50,794 1,133 10,814
Amortization of tax regulatory assets............................. 30,419 38,702 23,908
Amortization of goodwill.......................................... 18,416 18,420 19,341
Preferred stock dividends......................................... 19,733 18,172 22,988
Other, net........................................................ (18,472) (10,413) 343
---------- ---------- ----------
Total provision for income taxes.............................. $ 468,618 $ 376,802 $ 394,827
========== ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences........................................... $1,996,937 $1,245,297 $1,878,904
Customer receivables for future income taxes......................... 178,683 62,527 159,577
Competitive transition charge........................................ 1,289,438 1,070,161 537,114
Deferred sale and leaseback costs.................................... (77,099) (128,298) (129,775)
Nonutility generation costs.......................................... (178,393) -- --
Unamortized investment tax credits................................... (86,256) (85,641) (96,036)
Unused alternative minimum tax credits............................... -- (32,215) (101,185)
Other comprehensive income........................................... (115,395) -- --
Other................................................................ (323,696) (37,724) (17,334)
---------- ---------- ----------
Net deferred income tax liability*............................ $2,684,219 $2,094,107 $2,231,265
========== ========== ==========
<FN>
* 2001 excludes amounts in "Liabilities Related to Assets Pending Sale" on the
Consolidated Balance Sheet as of December 31, 2001.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
</FN>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include FirstEnergy Corp., a
public utility holding company, and its principal electric utility operating
subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating
Company (CEI), Pennsylvania Power Company (Penn), The Toledo Edison Company
(TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light
Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric
Company (Penelec). These utility subsidiaries are referred to throughout as
"Companies." FirstEnergy's 2001 results include the results of JCP&L, Met-Ed and
Penelec for the period November 7, 2001 through December 31, 2001 (see Note 2 -
Merger).The consolidated financial statements also include FirstEnergy's other
principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy
Facilities Services Group, LLC (FEFSG); MYR Group, Inc. (MYR); MARBEL Energy
Corporation (MARBEL); FirstEnergy Nuclear Operating Company (FENOC); GPU
Capital, Inc.; GPU Power, Inc.; FirstEnergy Service Company (FECO); and GPU
Service, Inc. (GPUS). FES provides energy-related products and services and,
through its FirstEnergy Generation Corp. (FGCO) subsidiary, operates
FirstEnergy's nonnuclear generation business. FENOC operates the Companies'
nuclear generating facilities. FEFSG is the parent company of several heating,
ventilating, air conditioning and energy management companies, and MYR is a
utility infrastructure construction service company. MARBEL is a fully
integrated natural gas company. GPU Capital owns and operates electric
distribution systems in foreign countries (see Note 2 - Merger) and GPU Power
owns and operates generation facilities in foreign countries. FECO and GPUS
provide legal, financial and other corporate support services to affiliated
FirstEnergy companies. Significant intercompany transactions have been
eliminated in consolidation.
The Companies follow the accounting policies and practices prescribed
by the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public
Utility Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and
the Federal Energy Regulatory Commission (FERC). The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States (GAAP) requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities. Actual results
could differ from these estimates. 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 Ohio, Pennsylvania and New Jersey. The Companies' retail customers
are metered on a cycle basis. Revenue is recognized for unbilled electric
service provided through the end of the year.
Receivables from customers include sales to residential, commercial
and industrial customers and sales to wholesale customers. There was no material
concentration of receivables as of December 31, 2001 or 2000, with respect to
any particular segment of FirstEnergy's 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 private sales of $50 million and
$150 million of receivables-backed investor certificates in 2000 and 2001,
respectively, in transactions that qualified for sale accounting treatment.
CFC's creditors are entitled to be satisfied first out of the proceeds of CFC's
assets. The 2001 private sale was used to repay a 1996 public sale of $150
million of receivables-backed investor certificates which was replaced under an
amended securitization agreement. FirstEnergy's retained interest in the pool of
receivables held by the trust (34% as of December 31, 2001) is stated at fair
value, reflecting adjustments for anticipated credit losses. Sensitivity
analyses reflecting a 10% and 20% increase in the rate of anticipated credit
losses did not significantly affect FirstEnergy's retained interest in the pool
of receivables. Of the $301 million sold to the trust and outstanding as of
December 31, 2001, FirstEnergy had a retained interest in $101 million of the
receivables. Accordingly, receivables recorded on the Consolidated Balance
Sheets were reduced by approximately $200 million due to these sales.
Collections of receivables previously transferred to the trust and used for the
purchase of new receivables from CFC during 2001, totaled approximately $2.2
billion. CEI and TE processed receivables for the trust and received servicing
fees of approximately $4.5 million in 2001. Expenses associated with the
factoring discount related to the sale of receivables were $12 million in 2001.
REGULATORY PLANS-
Ohio's 1999 electric utility restructuring law allowed Ohio electric
customers to select their generation suppliers beginning January 1, 2001,
provided for a five percent reduction on the generation portion of residential
customers' bills and the opportunity for utilities to recover transition costs,
including regulatory assets. Under this law, the PUCO approved FirstEnergy's
transition plan in 2000 as modified by a settlement agreement with major parties
to the transition plan, which it filed on behalf of OE, CEI and TE (Ohio
Companies). The settlement agreement included
approval for recovery of the amounts of transition costs 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 settlement also granted preferred access over FirstEnergy's subsidiaries to
nonaffiliated marketers, brokers and aggregators to 1,120 megawatts (MW) of
generation capacity through 2005 at established prices for sales to the Ohio
Companies' retail customers. The Ohio Companies' base electric rates for
distribution service under their prior respective regulatory plans were extended
from December 31, 2005 through December 31, 2007. The transition rate credits
for customers under their prior regulatory plans were also extended through the
Ohio Companies' respective transition cost recovery periods.
The transition plan itemized, or unbundled, the current price of
electricity into its component elements -- including generation, transmission,
distribution and transition charges. As required by the PUCO's rules,
FirstEnergy's transition plan also resulted in the 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 law, and planned changes in how FirstEnergy's
transmission system will be operated to ensure access to all users. Customer
prices are frozen through a five-year market development period (2001-2005),
except for certain limited statutory exceptions including a 5% reduction in the
price of generation for residential customers.
FirstEnergy's Ohio customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit of 45% for residential
customers, 30% for commercial customers and 15% for industrial customers. The
amount of the incentive serves to reduce the amortization of transition costs
during the market development period and will be recovered through the extension
of the transition cost recovery periods. If the customer shopping goals
established in the 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. Based on annualized shopping levels as of December 31, 2001,
FirstEnergy believes the maximum potential recovery reductions are approximately
$174 million (OE - $87 million, CEI - $52 million and TE - $35 million).
New Jersey is also evolving to a competitive electric utility
marketplace. In March 2001, the NJBPU issued a Final Decision and Order (Final
Order) with respect to JCP&L's rate unbundling, stranded cost and restructuring
filings, which superseded its 1999 Summary Order. The Final Order confirms rate
reductions set forth in the Summary Order, which remain in effect at increasing
levels through July 2003 with rates after July 31, 2003 to be determined in a
rate case commencing in 2002. The Final Order also confirms the right of
customers to select their generation suppliers effective August 1, 1999, and
includes the deregulation of electric generation service costs. The Final Order
confirms the establishment of a non-bypassable societal benefits charge to
recover costs which include nuclear plant decommissioning and manufactured gas
plant remediation, as well as a non-bypassable market transition charge (MTC)
primarily to recover stranded costs; however, the NJBPU deferred making a final
determination of the net proceeds and stranded costs related to prior generating
asset divestitures until JCP&L's request for an Internal Revenue Service (IRS)
ruling regarding the treatment of associated federal income tax benefits is
acted upon. Should the IRS ruling support the return of the tax benefits to
ratepayers, JCP&L would need to record a corresponding charge to income of
approximately $25 million; there would be no effect to FirstEnergy's net income
as the contingency existed prior to the merger.
JCP&L has an obligation to provide basic generation service (BGS),
that is, it must act as provider of last resort (PLR) to non-shopping customers
as a result of the NJBPU's restructuring plans. JCP&L obtains its supply of
electricity to meet its BGS obligation to non-shopping customers almost entirely
from contracted and open market purchases. JCP&L is permitted to defer for
future collection from customers the amounts by which its costs of supplying BGS
to non-shopping customers and costs incurred under nonutility generation (NUG)
agreements exceed amounts collected through BGS and MTC rates. As of December
31, 2001, the accumulated deferred cost balance totaled approximately $300
million, after giving effect to the reduction discussed below. The Final Order
provided for the ability to securitize stranded costs associated with the
divested Oyster Creek Nuclear Generation Station. In February 2002, JCP&L
received NJBPU authorization to issue $320 million of transition bonds to
securitize the recovery of these costs. The NJBPU order also provides for a
usage-based non-bypassable transition bond charge and for the transfer of the
bondable transition property to another entity. JCP&L plans to sell transition
bonds in the second quarter of 2002 which will be recognized on the Consolidated
Balance Sheet. The Final Order also allows for additional securitization of
JCP&L's deferred balance to the extent permitted by law upon application by
JCP&L and a determination by the NJBPU that the conditions of the New Jersey
restructuring legislation are met. There can be no assurance as to the extent,
if any, that the NJBPU will permit such securitization.
The obligation to provide BGS to non-shopping customers was bid out
for the period commencing August 1, 2002. In June 2001, the four incumbent New
Jersey electric distribution companies, including JCP&L, filed a joint proposal
seeking NJBPU approval of a competitive bidding process to procure supply for
the provision of BGS for the period of August 1, 2002 through July 31, 2003. In
December 2001, the NJBPU authorized the auctioning of BGS to meet the electric
demands of all customers who have not selected an alternative supplier. BGS for
all four companies, for the period of August 1, 2002 to July 31, 2003, was
simultaneously put out for bid. The auction, which ended on
February 13, 2002 and was approved by the NJBPU on February 15, 2002, removed
JCP&L's BGS obligation of 5,100 MW for the period from August 1, 2002 to July
31, 2003. The auction represents a transitional mechanism and a different model
for the procurement of BGS commencing August 1, 2003 may be adopted.
On September 26, 2001, the NJBPU approved the merger between
FirstEnergy and GPU, Inc., (see Note 2 - Merger) subject to the terms and
conditions set forth in a Stipulation of Settlement which had been signed by the
major parties in the merger discussions. Under this Stipulation of Settlement,
FirstEnergy agreed to reduce JCP&L's regulatory assets by $300 million, in order
to ensure that customers receive the benefit of future merger savings. JCP&L
wrote off $300 million of its deferred costs upon receipt of the final
regulatory approval for the merger, which occurred on October 29, 2001.
Pennsylvania enacted its electric utility competition law in 1996 with
the phase-in of customer choice for generation suppliers completed as of January
1, 2001. The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and
Penelec which essentially resulted in the deregulation of their respective
generation businesses.
In 2000, the PPUC disallowed a portion of the requested additional
stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate
restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS
ruling regarding the return of certain unamortized investment tax credits and
excess deferred income tax benefits to ratepayers. Similar to JCP&L's situation,
if the IRS ruling ultimately supports returning these tax benefits to
ratepayers, Met-Ed and Penelec would then reduce stranded costs by approximately
$12 million and $25 million, respectively, plus interest and record a
corresponding charge to income. Similar to JCP&L, there would be no effect to
FirstEnergy's net income.
As a result of their generating asset divestitures, Met-Ed and Penelec
obtain their supply of electricity to meet their PLR obligations almost entirely
from contracted and open market purchases. During 2000, their purchased power
costs substantially exceeded the amounts they could recover under their capped
generation rates which are in effect for varying periods, pursuant to their 1998
rate restructuring plans. In November 2000, Met-Ed and Penelec filed a petition
with the PPUC seeking permission to defer for future recovery their energy costs
in excess of amounts reflected in their capped generation rates. In January
2001, the PPUC consolidated this petition with the FirstEnergy/GPU merger
proceeding (see Note 2 - Merger) for consideration and resolution in accordance
with the merger procedural schedule.
In June 2001, Met-Ed, Penelec and FirstEnergy entered into a
Settlement Stipulation with all of the major parties in the combined merger and
rate relief proceedings, that, in addition to resolving certain issues
concerning the PPUC's approval of the FirstEnergy/GPU merger, also addressed
Met-Ed's and Penelec's request for PLR rate relief. On June 20, 2001, the PPUC
entered orders approving the Settlement Stipulation, which approved the merger
and provided Met-Ed and Penelec PLR rate relief. Met-Ed and Penelec are
permitted to defer for future recovery the difference between their actual
energy costs and those reflected in their capped generation rates, retroactive
to January 1, 2001. Deferral accounting will continue for such cost differences
through December 31, 2005; should energy costs incurred by Met-Ed and Penelec
during that period be below their respective capped generation rates, the
difference would be used to reduce their recoverable deferred costs. Met-Ed's
and Penelec's PLR obligations have been extended through December 31, 2010.
Met-Ed's and Penelec's competitive transition charge (CTC) revenues will be
applied first to PLR costs, then to non-NUG stranded costs and finally to NUG
stranded costs through December 31, 2010. Met-Ed and Penelec would be permitted
to recover any remaining stranded costs through a continuation of the CTC, after
December 31, 2010, however, such recovery would extend to no later than December
31, 2015. Any amounts not expected to be recovered by December 31, 2015 would be
written off at the time such nonrecovery becomes probable.
Several parties had filed Petitions for Review with the Commonwealth
Court of Pennsylvania regarding the PPUC's orders. On February 21, 2002, the
Court affirmed the PPUC decision regarding the FirstEnergy/GPU merger, remanding
the decision to the PPUC only with respect to the issue of merger savings. The
Court reversed the PPUC's decision regarding the PLR obligations of Met-Ed and
Penelec, and denied the related requests for rate relief by Met-Ed and Penelec.
FirstEnergy is considering its response to the Court's decision, which could
include asking the Pennsylvania Supreme Court to review the decision.
FirstEnergy is unable to predict the outcome of these matters.
All of the Companies' regulatory assets are expected to continue to be
recovered under provisions of the Ohio transition plan and the respective
Pennsylvania and New Jersey regulatory plans. 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 were being recovered through rates. Under OE's prior regulatory plan,
which was terminated at the end of 2000, and Penn's rate restructuring plan,
OE's and Penn's cumulative additional capital recovery and regulatory asset
amortization amounted to $1.424 billion.
The application of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71),
was discontinued in 1997 with respect to CEI's and TE's nuclear operations; in
1998 with respect to Penn's, Met-Ed's and Penelec's generation operations; in
1999 with respect to JCP&L's generation operations and in 2000 with respect to
OE's generation business and the nonnuclear generation businesses of CEI and TE.
JCP&L, Met-Ed and Penelec subsequently divested substantially all of their
generating assets. The Securities and Exchange Commission (SEC) issued
interpretive guidance regarding asset impairment measurement, concluding that
any supplemental regulated cash flows such as a 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 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, 2001.
SFAS 71
Discontinued
Net Assets Total Assets
--------------------------------------------------------
(In millions)
OE.......... $ 984 $7,218
CEI......... 1,425 5,856
TE.......... 601 2,572
Penn........ 88 960
JCP&L....... 46 8,040
Met-Ed...... 18 3,607
--------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT-
Property, plant and equipment reflects original cost (except for the
Ohio Companies' and Penn's nuclear generating units and the former GPU
companies' properties which were adjusted to fair value), including payroll and
related costs such as taxes, employee benefits, administrative and general
costs, and interest costs. In addition to FirstEnergy's wholly-owned facilities,
JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility --
its net book value was approximately $21.5 million as of December 31, 2001.
FirstEnergy also shares ownership interests in various foreign properties with
an aggregate net book value of $1.9 billion, representing the fair value of
FirstEnergy's interest.
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 respective annual composite rates for the Companies' electric plant in 2001,
2000 and 1999 (post merger periods only for JCP&L, Met-Ed and Penelec) are shown
in the following table:
Annual Composite
Depreciation Rate
---------------------------------------------------------
2001 2000 1999
---- ---- ----
OE............... 2.7% 2.8% 3.0%
CEI.............. 3.2 3.4 3.4
TE............... 3.5 3.4 3.4
Penn............. 2.9 2.6 2.5
JCP&L............ 3.4
Met-Ed........... 3.0
Penelec.......... 2.9
---------------------------------------------------------
Annual depreciation expense in 2001 included approximately $128.7
million for future decommissioning costs applicable to the Companies' ownership
and leasehold interests in five nuclear generating units, a demonstration
nuclear reactor owned by a wholly-owned subsidiary of JCP&L, Met-Ed and Penelec
and decommissioning liabilities for previously divested GPU nuclear generating
units. The 2001 amounts reflected increases of approximately $60 million from
implementing the Ohio utilities' transition plan in 2001. The Companies' share
of the future obligation to decommission these units is approximately $2.5
billion in current dollars and (using a 4.0% escalation rate) approximately $5.4
billion in future dollars. The estimated obligation and the escalation rate were
developed based on site specific studies. Decommissioning of the demonstration
nuclear reactor is expected to be completed in 2003; payments for
decommissioning of the nuclear generating units are expected to begin in 2014,
when actual decommissioning work is expected to begin. The Companies have
recovered approximately $568 million for decommissioning through their electric
rates from customers through December 31, 2001. The Companies have also
recognized an estimated liability of approximately $46.5 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.
In July 2001, the Financial Accounting Standards Board issued SFAS
143, "Accounting for Asset Retirement Obligations." The new statement provides
accounting treatment for retirement obligations associated with tangible
long-lived assets with adoption required by January 1, 2003. SFAS 143 requires
the fair value of a liability for an asset retirement obligation be recorded in
the period in which it is incurred. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. Over time
the capitalized costs are depreciated and the present value of the asset
retirement liability increases, resulting in a period expense. Upon retirement,
a gain or loss will be recorded if the costs to settle the retirement obligation
differ from the carrying amount. Under the new standard, additional assets and
liabilities relating principally to nuclear decommissioning obligations will be
recorded, the pattern of expense recognition will change and income from the
external decommissioning trusts will be recorded as investment income.
FirstEnergy is currently assessing the new standard and has not yet quantified
the impact on its financial statements.
NUCLEAR FUEL-
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. The
Companies amortize the cost of nuclear fuel based on the rate of consumption.
INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and accounting
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred income taxes. Deferred income tax liabilities
related to tax and accounting basis differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid.
RETIREMENT BENEFITS-
FirstEnergy's 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. On December 31,
2001, the GPU pension plans were merged with the FirstEnergy plan. FirstEnergy
uses the projected unit credit method for funding purposes and was not required
to make pension contributions during the three years ended December 31, 2001.
The assets of the pension plan consist primarily of common stocks, United States
government bonds and corporate bonds. The FirstEnergy and GPU postretirement
benefit plans are currently separately maintained; the information shown below
is aggregated as of December 31, 2001. Costs for the year 2001 include the
former GPU companies' pension and other postretirement benefit costs for the
period November 7, 2001 through December 31, 2001.
FirstEnergy provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee deductibles and copayments,
are also available to retired employees, their dependents and, under certain
circumstances, their survivors. FirstEnergy pays insurance premiums to cover a
portion of these benefits in excess of set limits; all amounts up to the limits
are paid by FirstEnergy. FirstEnergy recognizes the expected cost of providing
other postretirement benefits to employees and their beneficiaries and covered
dependents from the time employees are hired until they become eligible to
receive those benefits.
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
---------------- -----------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1...... $1,506.1 $1,394.1 $ 752.0 $ 608.4
Service cost............................ 34.9 27.4 18.3 11.3
Interest cost........................... 133.3 104.8 64.4 45.7
Plan amendments......................... 3.6 41.3 -- --
Actuarial loss.......................... 123.1 17.3 73.3 121.7
Voluntary early retirement program...... -- 23.4 2.3 --
GPU acquisition......................... 1,878.3 -- 716.9 --
Benefits paid........................... (131.4) (102.2) (45.6) (35.1)
-------------------------------------------------------------------------------------------
Benefit obligation as of December 31.... 3,547.9 1,506.1 1,581.6 752.0
-------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1 1,706.0 1,807.5 23.0 4.9
Actual return on plan assets............ 8.1 0.7 12.7 (0.2)
Company contribution.................... -- -- 43.3 18.3
GPU acquisition......................... 1,901.0 -- 462.0 --
Benefits paid........................... (131.4) (102.2) (6.0) --
-------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 3,483.7 1,706.0 535.0 23.0
-------------------------------------------------------------------------------------------
Funded status of plan................... (64.2) 199.9 (1,046.6) (729.0)
Unrecognized actuarial loss (gain)...... 222.8 (90.9) 212.8 147.3
Unrecognized prior service cost......... 87.9 93.1 17.7 20.9
Unrecognized net transition obligation
(asset)................................ -- (2.1) 101.6 110.9
-------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost.......... $ 246.5 $ 200.0 $ (714.5) $(449.9)
===========================================================================================
Assumptions used as of December 31:
Discount rate........................... 7.25% 7.75% 7.25% 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, 2001 were computed as follows:
Other
Pension Benefits Postretirement Benefits
------------------------ -------------------------
2001 2000 1999 2001 2000 1999
------------------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 34.9 $ 27.4 $ 28.3 $18.3 $11.3 $ 9.3
Interest cost........................... 133.3 104.8 102.0 64.4 45.7 40.7
Expected return on plan assets.......... (204.8) (181.0) (168.1) (9.9) (0.5) (0.4)
Amortization of transition obligation
(asset)................................ (2.1) (7.9) (7.9) 9.2 9.2 9.2
Amortization of prior service cost...... 8.8 5.7 5.7 3.2 3.2 3.3
Recognized net actuarial loss (gain).... -- (9.1) -- 4.9 -- --
Voluntary early retirement program...... 6.1 17.2 -- 2.3 -- --
------------------------------------------------------------------------------------------------------
Net benefit cost........................ $ (23.8) $ (42.9) $ (40.0) $92.4 $68.9 $62.1
======================================================================================================
The composite health care trend rate assumption is approximately 10%
in 2002, 9% in 2003 and 8% in 2004, trending to 4%-6% 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 $14.6 million and the postretirement benefit obligation by $151.2
million. A decrease in the same assumption by one percentage point would
decrease the total service and interest cost components by $12.7 million and the
postretirement benefit obligation by $131.3 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 at cost, which approximates their fair market value. Noncash
financing and investing activities included the 2001 FirstEnergy common stock
issuance of $2.6 billion for the GPU acquisition and capital lease transactions
amounting to $3.1 million, $89.3 million and $36.2 million for the years 2001,
2000 and 1999, respectively. Commercial paper transactions of OES Fuel,
Incorporated (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 currently payable long-term debt on
the Consolidated Balance Sheets in anticipation of the expiration of the related
long-term financing agreement in March 2002 (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:
2001 2000
- -------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------------------------
(In millions)
Long-term debt*................... $12,897 $13,097 $5,853 $6,010
Preferred stock................... $ 636 $ 626 $ 247 $ 243
Investments other than cash
and cash equivalents:
Debt securities:
Maturity (5-10 years)...... $ 439 $ 402 $ 460 $ 441
Maturity (more than 10 years) 990 1,009 1,026 1,051
Equity securities............. 15 15 16 16
All other..................... 1,730 1,734 924 935
- --------------------------------------------------------------------------------
$ 3,174 $ 3,160 $2,426 $2,443
================================================================================
* Excluding approximately $1.75 billion of long-term in 2001 debt related to
pending divestitures.
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 corporations with credit
ratings similar to the Companies' ratings. Long-term debt and preferred stock
subject to mandatory redemption of the former GPU companies were recognized at
fair value in connection with the merger.
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, FirstEnergy 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 (EITF)
Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities,"
with gains and losses recognized in the Consolidated Statements of Income.
On January 1, 2001, FirstEnergy 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 to January 1,
2001 was a charge of $8.5 million (net of $5.8 million of income taxes) or $.03
per share of common stock. The reported results of operations for the years
ended December 31, 2000 and 1999 would not have been materially different if
this accounting had been in effect during those years.
FirstEnergy is exposed to financial risks resulting from the
fluctuation of interest rates and commodity prices, including electricity,
natural gas and coal. To manage the volatility relating to these exposures,
FirstEnergy uses a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes and, to a lesser extent,
for trading purposes. FirstEnergy's Risk Policy Committee, comprised of
executive officers, exercises an independent risk oversight function to ensure
compliance with corporate risk management policies and prudent risk management
practices.
FirstEnergy uses derivatives to hedge the risk of price, interest rate
and foreign currency fluctuations. FirstEnergy's primary ongoing hedging
activity involves cash flow hedges of electricity and natural gas purchases. The
maximum periods over which the variability of electricity and natural gas cash
flows are hedged are two and three years, respectively. Gains and losses from
hedges of commodity price risks are included in net income when the underlying
hedged commodities are delivered. FirstEnergy entered into interest rate
derivative transactions during 2001 to hedge a portion of the anticipated
interest payments on debt related to the GPU acquisition. Gains and losses from
hedges of anticipated interest payments on acquisition debt will be included in
net income over the periods that hedged interest payments are made - 5, 10 and
30 years. The current net deferred loss of $169.4 million included in
Accumulated Other Comprehensive Loss (AOCL) as of December 31, 2001, for
derivative hedging activity, as compared to the December 31, 2000 balance of
$44.2 million (including the SFAS 133 cumulative adjustment) in deferred gains,
resulted from a $181.1 million reduction related to current hedging activity and
a $32.5 million reduction due to net hedge gains included in earnings during the
year. Approximately $40.7 million (after tax) of the current net deferred loss
on
derivative instruments in AOCL is expected to be reclassified to earnings during
the next twelve months as hedged transactions occur. However, the fair value of
these derivative instruments will fluctuate from period to period based on
various market factors and will generally be more than offset by the margin on
related sales and revenues.
REGULATORY ASSETS-
The Companies recognize, as regulatory assets, costs which the FERC,
PUCO, PPUC and NJBPU have authorized for recovery from customers in future
periods. Without such authorization, the costs would have been charged to income
as incurred. All regulatory assets are expected to continue to be recovered from
customers under the Companies' respective transition and regulatory 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 in 2000 and $257 million in 1999, as additional regulatory asset
amortization in accordance with their prior Ohio and current Pennsylvania
regulatory plans. The Ohio companies and Penn recognized incremental transition
cost recovery aggregating $309 million in accordance with the current Ohio
transition plan and Pennsylvania regulatory plan.
Net regulatory assets on the Consolidated Balance Sheets are comprised
of the following:
2001 2000
-----------------------------------------------------------------------
(In millions)
Regulatory transition charge................... $7,751.5 $3,489.0
Customer receivables for future income taxes... 433.0 139.9
Societal benefits charge....................... 166.6 --
Loss on reacquired debt........................ 80.0 51.0
Employee postretirement benefit costs.......... 98.6 15.3
Nuclear decommissioning, decontamination and
spent fuel disposal costs.................... 80.2 --
Provider of last resort costs.................. 116.2 --
Property losses and unrecovered plant costs.... 104.1 --
Other.......................................... 82.4 32.5
----------------------------------------------------------------------
Total $8,912.6 $3,727.7
======================================================================
2. MERGER:
On November 7, 2001, the merger of FirstEnergy and GPU became
effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000
(Merger Agreement). As a result of the merger, GPU's former wholly owned
subsidiaries, including JCP&L, Met-Ed and Penelec (collectively, the Former GPU
Companies), became wholly owned subsidiaries of FirstEnergy.
Under the terms of the Merger Agreement, GPU shareholders received the
equivalent of $36.50 for each share of GPU common stock they owned, payable in
cash and/or FirstEnergy common stock. GPU shareholders receiving FirstEnergy
shares received 1.2318 shares of FirstEnergy common stock for each share of GPU
common stock that they exchanged. The elections by GPU shareholders were subject
to proration since the total elections received would have resulted in more than
one-half of the GPU common stock being exchanged for FirstEnergy shares.
FirstEnergy borrowed the funds for the cash portion of the merger consideration,
approximately $2.2 billion, through a credit agreement dated as of October 2,
2001, from a group of banks led by Barclay's Bank Plc, as administrative agent;
the borrowings were refinanced with long-term debt on November 15, 2001.
FirstEnergy issued nearly 73.7 million shares of its common stock to GPU
shareholders for the share portion of the transaction consideration.
The merger was accounted for by the purchase method of accounting and,
accordingly, the Consolidated Statements of Income include the results of the
Former GPU Companies beginning November 7, 2001. The assets acquired and
liabilities assumed were recorded at estimated fair values as determined by
FirstEnergy's management based on information currently available and on current
assumptions as to future operations. The merger purchase accounting adjustments,
which were recorded in the records of GPU's direct subsidiaries, primarily
consist of: (1) revaluation of GPU's international operations to fair value; (2)
revaluation of property, plant and equipment; (3) adjusting preferred stock
subject to mandatory redemption and long-term debt to estimated fair value; (4)
recognizing additional obligations related to retirement benefits; and (5)
recognizing estimated severance and other compensation liabilities. Other assets
and liabilities were not adjusted since they remain subject to rate regulation
on a historical cost basis. The severance and compensation liabilities are based
on anticipated workforce reductions reflecting duplicate positions primarily
related to corporate support groups including finance, legal, communications,
human resources and information technology. The workforce reductions represent
the expected reduction of approximately 1,000 employees at a cost of
approximately $140 million. Merger related staffing reductions began in late
2001 and the remaining reductions are anticipated to occur through 2003 as
merger-related transition assignments are completed.
The merger greatly expanded the size and scope of our electric
business and the goodwill recognized primarily relates to the regulated services
segment.
The following table summarizes the estimated fair values of the assets
acquired and liabilities assumed at the date of acquisition. The allocation of
the purchase price is subject to adjustment within one year of the merger.
(In millions)
-----------------------------------------------------------
Current assets................... $ 1,027
Goodwill......................... 3,698
Regulatory assets................ 4,352
Other............................ 5,595
-------
Total assets acquired........ 14,672
Current liabilities.............. (2,615)
Long-term debt................... (2,992)
Other............................ (4,785)
--------
Total liabilities assumed.... (10,392)
Net assets acquired pending sale. 566
--------
Net assets acquired.............. $ 4,846
DIVESTITURES-INTERNATIONAL OPERATIONS
Prior to consummation of the GPU merger, FirstEnergy identified
certain GPU international operations (see below) for divestiture within twelve
months of the merger date. These operations constitute individual "lines of
business" as defined in Accounting Principles Board Opinion (APB) No. 30,
"Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions" with physically and operationally separable activities.
Application of EITF Issue No. 87-11, "Allocation of Purchase Price to Assets to
Be Sold," required that expected, pre-sale cash flows, including incremental
interest costs on related acquisition debt, of these operations be considered
part of the purchase price allocation. Accordingly, subsequent to the merger
date, results of operations and incremental interest costs related to these
international subsidiaries have not been included in FirstEnergy's Consolidated
Statement of Income. Additionally, assets and liabilities of these
international operations have been segregated under separate captions on the
Consolidated Balance Sheet as "Assets Pending Sale" and "Liabilities Related to
Assets Pending Sale" (see the tables below). The following entities are included
in such captions:
Australia - Gas Transmission (GasNet)
- -------------------------------------
GasNet Pty Ltd. and subsidiaries
GPU GasNet Trading Pty Ltd. (and related trusts)
United Kingdom - Electric Distribution
- --------------------------------------
Avon Energy Partners Holdings
Avon Energy Partners plc
Midlands Electricity plc
Midlands Power International Ltd.
Argentina - Electric Distribution
- ---------------------------------
GPU Empresa Distribuidora Electrica Regional S.A. and affiliates
In December 2001, FirstEnergy divested its Australian gas transmission
companies through an initial public offering of GasNet's common stock. The IPO
provided net proceeds of $125 million to FirstEnergy and immediately removed
$290 million of GasNet-related debt from FirstEnergy's consolidated debt.
On October 18, 2001, FirstEnergy and Aquila, Inc. (formerly UtiliCorp
United) announced that Aquila made an offer to FirstEnergy to purchase Avon
Energy Partners Holdings, FirstEnergy's wholly owned holding company of Midlands
Electricity plc, for $2.1 billion including the assumption of $1.7 billion of
debt. FirstEnergy accepted the offer upon completion of its merger with GPU and
regulatory approvals for the transaction have been received by Aquila. One
condition of regulatory approval requires that Aquila include a financial
partner in the transaction. The transaction must be completed by April 26, 2002,
or either party may terminate the original agreement. On March 18, 2002,
FirstEnergy announced that it finalized terms of the agreement in which Aquila
will acquire a 79.9 percent interest in Avon for approximately $1.9 billion
(including the transfer of $1.7 billion of debt).
FirstEnergy and Aquila together will own all of the outstanding shares
of Avon through a jointly owned subsidiary, with each company having a
50-percent voting interest.
Midlands maintains a defined benefit pension plan covering almost all
full-time employees of Midlands. The plan is maintained separately from the
FirstEnergy plan and will transfer upon completion of the sale. The pension
benefit obligations as of the November 7, 2001 merger date and December 31, 2001
were approximately $1,263 million and $1,264 million, respectively, with the net
change primarily due to actuarial gains of $12 million offset by benefits paid
of $11 million. The fair values of plan assets as of November 7, 2001 and
December 31, 2001, were approximately $1,313 million and $1,291 million,
respectively, with the change including benefits paid of approximately $11
million. The 2001 post-merger net periodic benefit income for the last seven
weeks of 2001 was approximately $3 million. The plan assumptions as of December
31, 2001 included a discount rate of 6.0%, an expected return on plan assets of
7.0% and a rate of compensation increase of 4.5%.
As with the other international subsidiaries identified above, GPU's
former Argentina operations, including GPU Empresa Distribuidora Electrica
Regional S.A., were identified by FirstEnergy for divestiture within twelve
months of the merger date. FirstEnergy is actively pursuing the sale of these
operations. FirstEnergy has determined the fair value of the Argentina
operations based on the best available information as of the date of the merger.
Subsequent to that date, a number of economic events have occurred in Argentina
which may have an impact on FirstEnergy's ability to realize the estimated fair
value of the Argentina operations. These events include currency devaluation,
restrictions on repatriation of cash, and the anticipation of future asset sales
in that region by competitors. FirstEnergy has determined that the current
economic conditions in Argentina have not eroded the fair value recorded for
these operations, and as a result, an impairment writedown of this investment is
not warranted as of December 31, 2001. FirstEnergy will continue to assess the
potential impact of these and other related events on the realizability of the
value recorded for the Argentina operations. Other international companies are
being considered for sale, however; as of the merger date those sales were not
judged to be probable of occurring within twelve months.
Post-merger results of operations and incremental interest costs for
the international operations included in "Assets Pending Sale" and "Liabilities
Related to Assets Pending Sale" on FirstEnergy's Consolidated Balance Sheet as
of December 31, 2001, are as follows:
Post-Merger Deferred Results of Operations and Interest Costs
International Operations
-------------------------------------------
United
Australia* Kingdom Argentina Total
---------- ------- --------- -----
(In millions)
Revenues......................... $4.0 $ 99.4 $ 28.5 $131.9
Expenses......................... 2.9 58.3 62.8 124.0
Capitalized incremental interest
costs.......................... 0.5 3.2 1.3 5.0
Net interest charges............. 1.2 20.2 3.2 24.6
Income taxes..................... 0.2 (20.5) (13.1) (33.4)
--------------------------------------------
Net income (loss) capitalized. $0.2 $ 44.6 $(23.1) $ 21.7
============================================
* Australian operations divested in December 2001
Consolidated Balance Sheets as of December 31, 2001
International Operations
----------------------------------
United
Kingdom Argentina Total
------- --------- -----
Assets Pending Sale
(In millions)
Current assets........................ $ 554 $ 41 $ 595
Property, plant and equipment......... 1,738 177 1,915
Investments........................... 142 -- 142
Deferred charges...................... 691 75 766
-----------------------------------
Total.............................. $3,125 $293 $3,418
===================================
Liabilities Related to Assets Pending Sale
Current liabilities:
Currently payable long-term debt... $ 316 $ 2 $ 318
Short-term debt.................... 207 27 234
Other.............................. 501 2 503
Long-term debt........................ 1,347 85 1,432
Deferred credits*...................... 455 13 468
------------------------------------
Total.............................. $2,826 $129 $2,955
====================================
Net Assets Pending Sale............... $ 299 $164 $ 463
====================================
* United Kingdom and Argentina are net of $3 million and $52 million,
respectively, related to currency translation adjustments.
SALE OF GENERATING ASSETS-
On November 29, 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants (with an aggregate net book value of $539 million as of
December 31, 2001) totaling 2,535 MW to NRG Energy, Inc. (NRG) for $1.5 billion
($1.355 billion in cash and $145 million in debt assumption). The net, after-tax
gain from the sale, based on the difference between the sale price of the plants
and their market price used in our Ohio restructuring transition plan, will be
credited to customers by reducing the transition cost recovery period.
FirstEnergy also entered into a power purchase agreement (PPA) with NRG. Under
the terms of the PPA, NRG is obligated to sell to FirstEnergy up to 10.5 billion
kilowatt-hours of electricity annually, similar to the average annual output of
the plants, through 2005. The sale is expected to close in mid-2002.
3. LEASES:
The Companies lease certain generating facilities, 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 expiration 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, 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.
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, 2001,
are summarized as follows:
2001 2000 1999
--------------------------------------------------------------------
(In millions)
Operating leases
Interest element............ $194.1 $202.4 $208.6
Other....................... 120.5 111.1 110.3
Capital leases
Interest element............ 8.0 12.3 17.5
Other....................... 35.5 64.2 76.1
-------------------------------------------------------------------
Total rentals............ $358.1 $390.0 $412.5
===================================================================
The future minimum lease payments as of December 31, 2001, are:
Operating Leases
-----------------------------------
Capital Lease Capital
Leases Payments Trusts Net
- --------------------------------------------------------------------------------
(In millions)
2002.......................... $ 6.1 $ 322.2 $ 169.5 $ 152.7
2003.......................... 6.2 332.9 176.5 156.4
2004.......................... 6.0 294.9 110.7 184.2
2005.......................... 5.4 314.6 128.8 185.8
2006.......................... 5.4 323.2 140.2 183.0
Years thereafter.............. 9.8 3,131.8 1,095.4 2,036.4
------------------------------------------------------------------------------
Total minimum lease payments.. 38.9 $4,719.6 $1,821.1 $2,898.5
======== ======== ========
Executory costs............... 8.8
--------------------------------------
Net minimum lease payments.... 30.1
Interest portion.............. 10.7
--------------------------------------
Present value of net minimum
lease payments.............. 19.4
Less current portion.......... 2.0
--------------------------------------
Noncurrent portion............ $17.4
======================================
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 FirstEnergy's common stock.
(B) EMPLOYEE STOCK OWNERSHIP PLAN-
FirstEnergy funds the matching contribution for its 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 2001, 2000
and 1999, 834,657 shares, 826,873 shares and 627,427 shares, respectively, were
allocated to employees with the corresponding expense recognized based on the
shares allocated method. The fair value of 5,117,375 shares unallocated as of
December 31, 2001, was approximately $179.0 million. Total ESOP-related
compensation expense was calculated as follows:
2001 2000 1999
- -----------------------------------------------------------------------------
(In millions)
Base compensation........................... $25.1 $18.7 $18.3
Dividends on common stock held by the ESOP
and used to service debt.................. (6.1) (6.4) (4.5)
- -----------------------------------------------------------------------------
Net expense............................. $19.0 $12.3 $13.8
=============================================================================
(C) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of the merger with GPU. No further stock based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 15
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2001 2000 1999
- ---------------------------------------------------------------------------
Restricted common shares granted..... 133,162 208,400 8,000
Weighted average market price ....... $35.68 $26.63 $30.89
Weighted average vesting period (years) 3.7 3.8 5.8
Dividends restricted................. * Yes Yes
-----------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Stock option activity under the FE Programs was as follows:
Number of Weighted Average
Stock Option Activity Options Exercise Price
- -----------------------------------------------------------------------------
Balance, December 31, 1998............ 364,286 $27.13
(182,330 options exercisable)......... 24.44
Options granted..................... 1,811,658 24.90
Options exercised................... 22,575 21.42
Balance, December 31, 1999............ 2,153,369 25.32
(159,755 options exercisable)......... 24.87
Options granted..................... 3,011,584 23.24
Options exercised................... 90,491 26.00
Options forfeited................... 52,600 22.20
Balance, December 31, 2000........... 5,021,862 24.09
(473,314 options exercisable)......... 24.11
Options granted..................... 4,240,273 28.11
Options exercised................... 694,403 24.24
Options forfeited................... 120,044 28.07
Balance, December 31, 2001............ 8,447,688 26.04
(1,828,341 options exercisable)....... 24.83
---------------------------------------------------------------------
As of December 31, 2001, the weighted average remaining contractual
life of outstanding stock options was 7.8 years.
Under the Executive Deferred Compensation Plan, covered employees can
direct a portion of their Annual Incentive Award and/or Long Term Incentive
Award into an unfunded FirstEnergy Stock Account to receive vested stock units.
An additional 20% premium is received in the form of stock units based on the
amount allocated to the FirstEnergy Stock Account. Dividends are calculated
quarterly on stock units outstanding and are paid in the form of additional
stock units. Upon withdrawal, stock units are converted to FirstEnergy shares.
Payout occurs three years from the date of deferral. As of December 31, 2001,
there were 234,558 stock units outstanding.
FirstEnergy continues to apply APB 25, "Accounting for Stock Issued to
Employees." As required by SFAS 123, "Accounting for Stock-Based Compensation,"
FirstEnergy has determined pro forma earnings as though FirstEnergy 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:
2001 2000 1999
- ----------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 8.3 7.6 6.4
Expected volatility......... 23.45% 21.77% 20.03%
Expected dividend yield..... 5.00% 6.68% 5.97%
Risk-free interest rate..... 4.67% 5.28% 5.97%
Fair value per option......... $4.97 $2.86 $3.42
---------------------------------------------------------------------------
The following table summarizes the pro forma effect of applying fair
value accounting to FirstEnergy's stock options.
2001 2000 1999
- -----------------------------------------------------------------------------
Net Income (000)
As Reported................. $646,447 $598,970 $568,299
Pro Forma................... $642,724 $597,378 $567,876
- --------------------------------------------------------------------------------
Earnings Per Share
of Common Stock -
Basic
As Reported................. $2.82 $2.69 $2.50
Pro Forma................... $2.80 $2.69 $2.50
Diluted*
As Reported................. $2.81 $2.69 $2.50
Pro Forma................... $2.79 $2.69 $2.50
* The denominator used in the calculation of diluted earnings per
share of common stock includes the weighted average number of
common shares outstanding (used as the denominator for the
calculation of basic earnings per share of common stock) plus
common stock equivalents resulting from the stock-based
compensation plans discussed above-including 723,931 for options
and 194,107 for stock units.
(D) PREFERRED AND PREFERENCE STOCK-
JCP&L's 7.52% Series K of preferred stock has a restriction which
prevents early redemption prior to June 2002. Penn's 7.75% series has a
restriction which prevents early redemption prior to July 2003. CEI's $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.
TE exercised its option to redeem all outstanding shares of five
series of preferred stock on February 1, 2002 as follows:
Series Outstanding Shares Call Price
------------------------------------------------------
$ 7.76 150,000 $102.44
$ 7.80 150,000 $101.65
$ 8.32 100,000 $102.46
$ 10.00 190,000 $101.00
$ 2.21 1,000,000 $ 25.25
-----------------------------------------------------
CEI redeemed, pursuant to redemption provisions of its $42.40 Series T
issue, all 200,000 shares outstanding on February 1, 2002 at a price of $500 per
share.
Met-Ed's and Penelec's preferred stock authorization consists of 10
million and 11.435 million shares, respectively, without par value. No preferred
shares are currently outstanding for the two companies.
The Companies' preference stock authorization consists of 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
- ---------------------------------------------------------------------------
CEI $ 7.35 C 10,000 $ 100
90.00 S 17,750 1,000
JCP&L 8.65% J 83,333 100
7.52% K 25,000 100
Penn 7.625% 7,500 100
- ---------------------------------------------------------------------------
Annual sinking fund requirements for the next five years are $30
million in 2002, $13 million in each year 2003 and 2004, and $4 million in each
year 2005 and 2006.
(F) SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED
DEBENTURES OF SUBSIDIARIES-
OE and CEI have each formed statutory business trusts as wholly owned
financing subsidiaries for which they own all of the respective common
securities. Each trust sold preferred securities and invested the gross proceeds
in subordinated debentures of the applicable parent company and the sole assets
of each trust are the applicable subordinated debentures. In each case, interest
payment provisions of the subordinated debentures match the distribution payment
provisions of the trust's preferred securities. In addition, upon redemption or
payment at maturity of subordinated debentures, the applicable trust's preferred
securities will be redeemed on a pro rata basis at their liquidation value.
Under certain circumstances, the applicable subordinated debentures could be
distributed to the holders of the outstanding preferred securities of the trust
in the event that the trust is liquidated. The applicable parent company has
effectively provided a full and unconditional guarantee of payments due on its
trust's preferred securities. Their respective trust preferred securities are
redeemable at 100% of their principal amount at the option of OE and, beginning
in December 2006, at the option of CEI.
Met-Ed and Penelec have each also formed statutory business trusts for
substantially similar transactions as OE and CEI. However, ownership of the
respective Met-Ed and Penelec trusts is through separate wholly-owned limited
partnerships, of which a wholly-owned subsidiary of each company is the sole
general partner. In these transactions, each trust invested the gross proceeds
from the sale of its trust preferred securities in the preferred securities of
the applicable limited partnership, which in turn invested those proceeds in the
7.35% and 7.34% subordinated debentures of Met-Ed and Penelec, respectively. In
each case, the applicable parent company has effectively provided a full and
unconditional guarantee of its obligations under its trust's preferred
securities. The Met-Ed and Penelec trust preferred securities are redeemable at
the option of Met-Ed and Penelec beginning in May 2004 and September 2004,
respectively, at 100% of their principal amount.
Additionally, JCP&L has formed a limited partnership for a
substantially similar transaction; however, no statutory trust is involved. That
limited partnership, of which JCP&L is the sole general partner, invested the
gross proceeds from the sale of its monthly income preferred securities (MIPS)
in JCP&L's 8.56% subordinated debentures. JCP&L has effectively provided a full
and unconditional guarantee of its obligations under its limited partnership's
MIPS. The limited partnership's MIPS are redeemable at the option of JCP&L at
100% of their principal amount. In all of these transactions, interest on the
subordinated debentures (and therefore the distributions on trust preferred
securities or MIPS) may be deferred for up to 60 months, but the parent company
may not pay dividends on, or redeem or acquire, any of its cumulative preferred
or common stock until deferred payments on its subordinated debentures are paid
in full.
The following table lists the subsidiary trusts and limited
partnership and information regarding their preferred securities outstanding as
of December 31, 2001.
- -----------------------------------------------------------------------------------------
Preferred Securities (a)
------------------------------
Stated Subordinated
Maturity Rate Value Debentures
- ------------------------------------------------------------------------------------------
(In millions)
Ohio Edison Financing Trust (b)...... 2025 9.00% $120.0 $123.7
Cleveland Electric Financing Trust (b) 2031 9.00% $100.0 $103.1
Met-Ed Capital Trust (c)............. 2039 7.35% $100.0 $103.1
Penelec Capital Trust (c)............ 2039 7.34% $100.0 $103.1
JCP&L, Capital L.P. (b).............. 2044 8.56% $125.0 $128.9
==========================================================================================
<FN>
(a) The liquidation value is $25 per security.
(b) The sole assets of the trust or limited partnership are the parent
company's subordinated debentures with the same rate and maturity date as
the preferred securities.
(c) The sole assets of the trust are the preferred securities of Met-Ed Capital II, L.P. and Penelec
Capital II, L.P., respectively, whose sole assets are the parent company's subordinated
debentures with the same rate and maturity date as the preferred securities.
</FN>
(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, 2001, the Companies' annual sinking and improvement fund
requirements for all bonds issued under the mortgages amounts to $66.9 million.
OE, TE and Penn expect to deposit funds in 2002 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. JCP&L, Met-Ed and Penelec
expect to fulfill their sinking and improvement fund obligation by providing
bondable property additions and/or retired bonds to the Trustee to meet their
annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases and long-term debt included in
"Liabilities Related to Assets Pending Sale") for the next five years are:
(In millions)
---------------------------------
2002.............. $1,654.7
2003.............. 928.1
2004.............. 1,421.1
2005.............. 853.3
2006.............. 1,432.5
---------------------------------
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 $287.6 million and noncancelable municipal bond insurance policies of
$493.9 million to pay principal of, or interest on, the pollution control
revenue bonds. To the extent that drawings are made under the letters of credit,
the Companies are entitled to a credit against their obligation to repay those
bonds. The Companies pay annual fees of 1.00% 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.
FirstEnergy had unsecured borrowings of $250 million as of December
31, 2001, supported by a $500 million long-term revolving credit facility
agreement which expires November 29, 2004. As of December 31, 2001, FirstEnergy
currently pays an annual facility fee of 0.25% on the total credit facility
amount. The fee is subject to change based on credit agency ratings for
FirstEnergy.
OE had no unsecured borrowings as of December 31, 2001 under 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 $141.5 million long-term bank credit agreement which expires March 31, 2002.
FirstEnergy does not anticipate extending the credit agreement. Accordingly, the
commercial paper and loans are reflected as currently payable long-term debt on
the December 31, 2001 Consolidated Balance Sheet. 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, 2001, accumulated other comprehensive income (loss) consisted of a
minimum liability for unfunded retirement benefits of $0.6 million, unrealized
gains on investments in securities available for sale of $1.0 million and
unrealized losses on derivative instrument hedges of $169.4 million.
5. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding as of December 31, 2001, consisted
of $688.3 million of bank borrowings and $159.8 million of OES Capital,
Incorporated commercial paper. Total borrowings include $233.8 million related
to pending divestitures (see Note 2 - Merger) that are included in "Liabilities
Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December
31, 2001. 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.
FirstEnergy and its subsidiaries have various credit facilities
(including a FirstEnergy $1 billion short-term revolving credit facility) with
domestic and foreign banks that provide for borrowings of up to $1.291 billion
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, FirstEnergy and its subsidiaries are required to pay annual
commitment fees that vary from 0.125% to 0.20%. These lines expire at various
times during 2002. The weighted average interest rates on short-term borrowings
outstanding as of December 31, 2001 and 2000, were 3.80% and 7.92%,
respectively.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
FirstEnergy's current forecast reflects expenditures of approximately
$3.4 billion for property additions and improvements from 2002-2006, of which
approximately $850 million is applicable to 2002. Investments for additional
nuclear fuel during the 2002-2006 period are estimated to be approximately $536
million, of which approximately $54 million applies to 2002. During the same
periods, the Companies' nuclear fuel investments are expected to be reduced by
approximately $507 million and $101 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 FirstEnergy's common stock over a three-year
period beginning in 1999. Repurchases were made on the open market, at
prevailing prices, and were funded primarily through the use of operating cash
flows. During 2001, 2000 and 1999, FirstEnergy repurchased and retired 550,000
shares (average price of $27.82 per share), 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 $1.2 billion of insurance coverage for replacement power costs.
Under these policies, the Companies can be assessed a maximum of approximately
$71 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.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $225 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2002 through 2006.
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
oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990.
SO2 reductions are being achieved by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions are being achieved through combustion controls and the generation of
more electricity at lower-emitting plants. In September 1998, the EPA finalized
regulations requiring additional NOx reductions from the Companies' Ohio and
Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions
of NOx emissions (an approximate 85% reduction in utility plant NOx emissions
from projected 2007 emissions) across a region of nineteen states and the
District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a
conclusion that such NOx emissions are contributing significantly to ozone
pollution in the eastern United States. State Implementation Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania submitted a SIP that requires compliance with the NOx budgets at
the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a
"draft" SIP that requires compliance with the NOx budgets at the Companies' Ohio
facilities by May 31, 2004. 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 if and how they are
ultimately implemented by the states in which the Companies operate affected
facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against 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,
FirstEnergy 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. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
Various environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2001, based on estimates of the
total costs of cleanup, the Companies' proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. The
Companies 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. In addition, JCP&L
has accrued liabilities for environmental remediation of former manufactured gas
plants in New Jersey; those costs are being recovered by JCP&L through a
non-bypassable societal benefits charge. The Companies have total accrued
liabilities aggregating approximately $60 million as of December 31, 2001.
FirstEnergy does not believe environmental remediation costs will have a
material adverse effect on its financial condition, cash flows or results of
operations.
OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant are described below.
Unit 2 of the Three Mile Island Nuclear Plant (TMI-2) was acquired by
FirstEnergy in 2001 as part of the merger with GPU. As a result of the 1979
TMI-2 accident, claims for alleged personal injury against JCP&L, Met-Ed,
Penelec and GPU were filed in the U.S. District Court for the Middle District of
Pennsylvania. In 1996, the District Court granted a motion for summary judgment
filed by GPU and dismissed the ten initial "test cases" which had been selected
for a test case trial, as well as all of the remaining 2,100 pending claims. In
November 1999, the U.S. Court of Appeals for the Third Circuit affirmed the
District Court's dismissal of the ten "test cases," but set aside the dismissal
of the additional pending claims, remanding them to the District Court for
further proceedings. In September 2000, GPU filed for a summary judgment in the
District Court. Meanwhile, the plaintiffs appealed to the Third Circuit for a
review of the District Court's decision placing limitations on the remaining
plaintiffs' suits. In April 2001, the Third Circuit affirmed the District
Court's decision. In July 2001, GPU renewed its motion for a summary judgment on
the remaining 2,100 claims in the District Court. On January 15, 2002, the
District Court granted GPU's amended motion for summary judgment. On February
14, 2002 plaintiffs filed a notice of appeal to the United States Court of
Appeals for the Third Circuit. In addition to the approximately 2,100 claims for
which summary judgment has been granted, there is other pending litigation
arising out of the TMI-2 accident. This litigation consists of the following:
eight personal injury cases that were not consolidated with the above-referenced
approximately 2,100 claims; two class actions brought on behalf of plaintiffs
alleging additional injuries diagnosed after the filing of the complaints in the
above-referenced case; a case alleging exposure during the post-accident cleanup
of the TMI-2 plant; and claims by individual businesses for economic loss
resulting from the TMI-2 accident. Although unable to predict the outcome of
this litigation, FirstEnergy believes that any liability to which it might be
subject by reason of the TMI-2 accident will not exceed its financial protection
under the Price-Anderson Act.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including the territory of JCP&L. In an investigation into
the causes of the outages and the reliability of the transmission and
distribution systems of all four New Jersey electric utilities, the NJBPU
concluded that there was not a prima facie case demonstrating that, overall,
JCP&L provided unsafe, inadequate or improper service to its customers. Two
class action lawsuits (subsequently consolidated into a single proceeding) were
filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU
companies seeking compensatory and punitive damages arising from the July 1999
service interruptions in the JCP&L territory. In May 2001, the court denied
without prejudice the defendants' motion seeking decertification of the class.
Discovery continues in the class action, but no trial date has been set. The
judge has set a schedule under which factual legal discovery would conclude in
March 2002, and expert reports would be exchanged by June 2002. In October 2001,
the court held argument on the plaintiffs' motion for partial summary judgment,
which contends that JCP&L is bound to several findings of the NJBPU
investigation. The plaintiffs' motion was denied by the Court in November 2001
and the
plaintiffs' motion to file an appeal of this decision was denied by the New
Jersey Appellate Division. JCP&L has also filed a motion for partial summary
judgement that is currently pending before the Superior Court. FirstEnergy is
unable to predict the outcome of these matters.
OTHER COMMITMENTS, GUARANTEES AND CONTINGENCIES-
GPU had made significant investments in foreign businesses and
facilities through its GPU Electric and GPU Power subsidiaries. Although
FirstEnergy will attempt to mitigate its risks related to foreign investments,
it faces additional risks inherent in operating in such locations, including
foreign currency fluctuations.
GPU Electric, through its subsidiary, Midlands, has a 40% equity
interest in a 586 MW power project in Pakistan (the Uch Power Project), which
commenced commercial operations in October 2000. GPU Electric's investment in
this project as of December 31, 2001 was approximately $38 million, plus a
guaranty letter of credit of $3.6 million, and its share of the projected
completion costs represents an additional $4.8 million commitment. Cinergy (the
former owner of 50% of Midlands Electricity plc) agreed to fund up to an
aggregate of $20 million of the required capital contributions, for a period of
one year from July 15, 1999, and "cash losses" which could be incurred on the
Uch Power Project, for a period of up to ten years from July 15, 1999. Cinergy
has reimbursed GPU Electric $4.9 million through December 31, 2001, leaving a
remaining commitment for future cash losses of up to $15.1 million. Midlands
also has a 31% equity interest in a 478 MW power project in Turkey (the Trakya
Power Project). Trakya is presently engaged in a foreign currency conversion
issue with TETTAS (the state owned electricity purchaser). Midlands established
a $16.5 million reserve for non-recovery relating to that issue as of December
31, 2001. These commitments and contingencies associated with Midlands will
transfer to the new partnership upon completion of the sale discussed in Note 2
- - Merger, with FirstEnergy being responsible for its lower proportionate
interest.
EI Barranquilla, a wholly owned subsidiary of GPU Power, is an equity
investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which
owns a Colombian independent power generation project. As of December 31, 2001,
GPU Power has an investment of approximately $109.4 million in TEBSA and is
committed, under certain circumstances, to make additional standby equity
contributions of $21.3 million, which FirstEnergy has guaranteed. The total
outstanding senior debt of the TEBSA project is $315 million at December 31,
2001. The lenders include the Overseas Private Investment Corporation, US Export
Import Bank and a commercial bank syndicate. GPU had guaranteed the obligations
of the operators of the TEBSA project, up to a maximum of $5.8 million (subject
to escalation) under the project's operations and maintenance agreement.
GPU believed that various events of default have occurred under the
loan agreements relating to the TEBSA project. In addition, questions have been
raised as to the accuracy and completeness of information provided to various
parties to the project in connection with the project's formation. FirstEnergy
continues to discuss these issues and related matters with the project lenders,
CORELCA (the government owned Colombian electric utility with an ownership
interest in the project) and the Government of Colombia.
Moreover, in September 2001, the DIAN (the Colombian national tax
authority) had presented TEBSA with a statement of charges alleging that certain
lease payments made under the Lease Agreement with Los Amigos Leasing Company
(an indirect wholly owned subsidiary of GPU Power) violated Colombian foreign
exchange regulations and were, therefore, subject to substantial penalties. The
DIAN has calculated a statutory penalty amounting to approximately $200 million
and gave TEBSA two months to respond to the statement of charges. In November
2001, TEBSA filed a formal response to this statement of charges. TEBSA is
continuing to review the DIAN's position and has been advised by its Colombian
counsel that the DIAN's position is without substantial legal merit. FirstEnergy
is unable to predict the outcome of these matters.
7. SEGMENT INFORMATION:
FirstEnergy operates under the following reportable segments:
regulated services, competitive services and other (primarily corporate support
services and international operations acquired in the GPU merger). FirstEnergy's
primary segment is its regulated services, which include eight electric utility
operating companies in Ohio, Pennsylvania and New Jersey that formerly provided
bundled electric service. Its other material business segment consists of the
subsidiaries that operate unregulated energy and energy-related businesses.
The regulated services segment designs, constructs, operates and
maintains FirstEnergy's 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 a portion of its required generation through power supply
agreements with the competitive services segment.
The competitive services segment includes all domestic unregulated
energy and energy-related services including commodity sales (both electricity
and natural gas) in the retail and wholesale markets, marketing, generation and
sourcing of commodity requirements, as well as other competitive
energy-application services. Competitive products are increasingly marketed to
customers as bundled services.
2000 and 1999 financial data are pro forma amounts to represent 2001
business segment organizations and operations. Financial data for these business
segments are as follows:
Segment Financial Information
-----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
--------- ----------- ----- ----------- ------------
(In millions)
2001
----
External revenues..................... $ 5,729 $2,165 $ 11 $ 94 (a) $ 7,999
Internal revenues..................... 1,480 2,011 350 (3,841)(b) --
Total revenues..................... 7,209 4,176 361 (3,747) 7,999
Depreciation and amortization......... 841 21 28 -- 890
Net interest charges.................. 571 25 74 (114)(b) 556
Income taxes.......................... 469 45 (40) -- 474
Income before cumulative effect of a
change in accounting............... 640 66 (51) -- 655
Net income............................ 640 57 (51) -- 646
Total assets.......................... 28,054 2,981 6,317 -- 37,352
Property additions.................... 447 375 30 -- 852
2000
----
External revenues..................... $ 5,415 $1,545 $ 1 $ 68 (a) $ 7,029
Internal revenues..................... 1,364 2,280 306 (3,950)(b) --
Total revenues..................... 6,779 3,825 307 (3,882) 7,029
Depreciation and amortization......... 919 13 2 -- 934
Net interest charges.................. 558 10 19 (58)(b) 529
Income taxes.......................... 297 95 (15) -- 377
Net income............................ 465 137 (3) -- 599
Total assets.......................... 14,682 2,685 574 -- 17,941
Property additions.................... 422 126 40 -- 588
1999
----
External revenues..................... $ 5,448 $ 796 $ 60 $ 16 (a) $ 6,320
Internal revenues..................... 1,274 2,240 184 (3,698)(b) --
Total revenues..................... 6,722 3,036 244 (3,682) 6,320
Depreciation and amortization......... 928 10 -- -- 938
Net interest charges.................. 613 8 6 (55)(b) 572
Income taxes.......................... 288 90 17 -- 395
Net income............................ 414 129 25 -- 568
Total assets.......................... 16,792 1,030 402 -- 18,224
Property additions.................... 418 207 -- -- 625
<FN>
Reconciling adjustments to segment operating results from internal management
reporting to consolidated external financial reporting:
(a) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes.
(b) Elimination of intersegment transactions.
</FN>
Products and Services
---------------------
Energy Related
Electricity Oil & Gas Sales and
Year Sales Sales Services
---- ----------- --------- --------------
(In millions)
2001 $6,078 $792 $693
2000 5,537 582 563
1999 5,253 203 503
2001 Geographic Information Revenues Assets
--------------------------- -------- ------
(In millions)
United States............... $7,991 $32,187
Foreign countries*.......... 8 5,165
------ -------
Total..................... $7,999 $37,352
* See Note 2 for discussion of planned divestitures of international
operations.
8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by quarter for
2001 and 2000.
March 31, June 30, September 30, December 31,
Three Months Ended 2001 2001 2001 2001(a)
- ----------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues....................................... $1,985.7 $1,804.1 $1,951.6 $2,257.9
Expenses....................................... 1,669.4 1,416.7 1,412.1 1,816.0
- ----------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes........ 316.3 387.4 539.5 441.9
Net Interest Charges........................... 126.3 121.0 124.1 184.3
Income Taxes................................... 83.8 120.4 181.3 89.0
- ----------------------------------------------------------------------------------------------------------------
Income Before
Cumulative Effect of Accounting Change...... 106.2 146.0 234.1 168.6
Cumulative Effect of Accounting Change
(Net of Income Taxes) (Note 1).............. (8.5) -- -- --
- ----------------------------------------------------------------------------------------------------------------
Net Income..................................... $ 97.7 $ 146.0 $ 234.1 $ 168.6
================================================================================================================
Basic Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $ .49 $ .67 $ 1.07 $ .64
Cumulative Effect of Accounting Change
(Net of Income Taxes) (Note 1)............ (.04) -- -- --
- ----------------------------------------------------------------------------------------------------------------
Basic Earnings Per Share of Common Stock....... $ .45 $ .67 $ 1.07 $ .64
- ----------------------------------------------------------------------------------------------------------------
Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $ .49 $ .67 $ 1.06 $ .64
Cumulative Effect of Accounting Change
(Net of Income Taxes) (Note 1)............ (.04) -- -- --
- ----------------------------------------------------------------------------------------------------------------
Diluted Earnings Per Share of Common Stock..... $ .45 $ .67 $ 1.06 $ .64
================================================================================================================
<FN>
(a) Results for the former GPU companies are included from the November 7, 2001
acquisition date through December 31, 2001.
</FN>
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
- ----------------------------------------------------------------------------------------------------------------
Net Income..................................... $ 140.9 $ 134.6 $ 198.2 $ 125.3
================================================================================================================
Basic and Diluted Earnings per Share of
Common Stock................................ $ .63 $ .60 $ .89 $ .57
================================================================================================================
9. PRO FORMA COMBINED CONDENSED FIRSTENERGY STATEMENTS OF INCOME (UNAUDITED):
The following pro forma combined condensed statements of income of
FirstEnergy give effect to the FirstEnergy/GPU merger as if it had been
consummated on January 1, 2000, with the purchase accounting adjustments
actually recognized in the business combination (see Note 2 - Merger). The pro
forma combined condensed financial statements have been prepared to reflect the
merger under the purchase method of accounting with FirstEnergy acquiring GPU.
Under the purchase method of accounting, tangible and identifiable intangible
assets acquired and liabilities assumed are recorded at their estimated fair
values. The excess of the purchase price, including estimated fees and expenses
related to the merger, over the net assets acquired (which included existing
goodwill of $1.9 billion) is classified as goodwill and amounts to an
additional $2.3 billion. In addition, the pro forma adjustments reflect a
reduction in debt from application of the proceeds from certain pending
divestitures as well as the related reduction in interest costs.
Year Ended December 31,
-----------------------
2001 2000
---- ----
(In millions, except per share amounts)
Revenues................................. $12,108 $11,703
Expenses................................. 9,768 9,377
- -------------------------------------------------------------------------
Income Before Interest and Income Taxes.. 2,340 2,326
Net Interest Charges..................... 941 977
Income Taxes............................. 561 527
- -------------------------------------------------------------------------
Net Income............................... $ 838 $ 822
- -------------------------------------------------------------------------
Earnings per Share of Common Stock....... $ 2.87 $ 2.77
- -------------------------------------------------------------------------