EXHIBIT 13
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. PricewaterhouseCoopers
LLP, independent public accountants, have expressed an unqualified opinion on
the Company's 2002 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; appointment of
independent accountants to conduct the normal annual audit and special purpose
audits as may be required; reviewing and approving all services, including any
non-audit services, performed for the Company by the independent public
accountants and reviewing the related fees; 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 reviews the
independent accountants' internal quality control procedures and reviews all
relationships between the independent accountants and the Company, in order to
assess the auditors' independence. The Committee also reviews management's
programs to monitor compliance with the Company's policies on business ethics
and risk management. The Audit Committee held nine meetings in 2002.
Richard H. Marsh
Senior Vice President
and Chief Financial Officer
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
1
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of FirstEnergy Corp.:
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
common stockholders' equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of FirstEnergy Corp.
and subsidiaries as of December 31, 2002, and the results of their operations
and their cash flows for the year then ended in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion. The consolidated financial statements of
FirstEnergy Corp. and subsidiaries as of December 31, 2001 and for each of the
two years in the period ended December 31, 2001, prior to the revisions
described in Notes 2(E) and 8, were audited by other independent auditors who
have ceased operations. Those independent auditors expressed an unqualified
opinion on those financials statements, in their report dated March 18, 2002.
As discussed in Note 2(E) to the consolidated financial statements, the Company
changed its method of accounting for goodwill in 2002.
As discussed in Note 2(L) and Note 2(M) to the consolidated financial
statements, the Company has restated its previously issued consolidated
financial statements for the year ended December 31, 2002.
As discussed above, the consolidated financial statements of FirstEnergy Corp.
and subsidiaries as of December 31, 2001 and for each of the two years in the
period ended December 31, 2001 were audited by other independent auditors who
have ceased operations. As described in Note 2(E) to the consolidated financial
statements, the financial statements have been revised to include the
transitional disclosures required by Statement of Financial Accounting Standards
No. 142, Goodwill and Other Intangible Assets, which was adopted by the Company
as of January 1, 2002. Additionally, as described in Note 8 to the consolidated
financial statements, the Company changed the composition of its reportable
segments in 2002. We audited the transitional disclosures described in Note 2(E)
and the adjustments that were applied to restate the 2001 and 2000 reportable
segments disclosures discussed in Note 8. In our opinion, such adjustments to
the reportable segments disclosures are appropriate and have been properly
applied and the transitional disclosures for 2001 and 2000 are appropriate.
However, we were not engaged to audit, review, or apply any procedures to the
2001 and 2000 consolidated financial statements of the Company other than with
respect to such transitional disclosures and adjustments to the reportable
segments disclosures and, accordingly, we do not express an opinion or any other
form of assurance on the 2001 and 2000 consolidated financial statements taken
as a whole.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003, except as to Note 2(L), which is as of May 9, 2003, and Notes
2(M) and 8, which are as of August 18, 2003
2
The following report is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). This report has not been reissued by Andersen and Andersen did
not consent to the incorporation by reference of this report (as included in
this form 10-K/A) into any of the Company's registration statements.
As discussed in Note 2(E) to the consolidated financial statements, the Company
has revised its consolidated financial statements for the years ended December
31, 2001 and 2000 to include the transitional disclosures required by Statement
of Financial Accounting Standards No. 142, "Goodwill and Other Intangible
Assets." Additionally, as discussed in Note 8 to the consolidated financial
statements, the Company has revised its consolidated financial statements for
the years ended December 31, 2001 and 2000 to reflect changes in the composition
of its reportable segments in 2002. The Andersen report does not extend to these
changes. The revisions to the 2001 and 2000 financial statements related to
these transitional disclosures and the revisions that were applied to restate
the 2001 and 2000 reportable segments disclosures were reported on by
PricewaterhouseCoopers LLP, as stated in their report appearing herein.
REPORT OF PREVIOUS 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
3
FIRSTENERGY CORP.
SELECTED FINANCIAL DATA
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 1999 1998
- -------------------------------- ----------- ----------- ----------- ----------- -----------
RESTATED
(SEE NOTES
2(L) AND (M))
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues ............................................ $12,230,526 $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906
----------- ----------- ----------- ----------- -----------
Income Before Discontinued Operations,
Extraordinary Item and Cumulative
Effect of Accounting Changes ..................... $ 640,280 $ 654,946 $ 598,970 $ 568,299 $ 441,396
----------- ----------- ----------- ----------- -----------
Net Income .......................................... $ 552,804 $ 646,447 $ 598,970 $ 568,299 $ 410,874
----------- ----------- ----------- ----------- -----------
Basic Earnings per Share of Common Stock:
Before Discontinued Operations,
Extraordinary Item and Cumulative
Effect of Accounting Change .................... $ 2.19 $ 2.85 $ 2.69 $ 2.50 $ 1.95
After Discontinued Operations, Extraordinary
Item and Cumulative Effect of
Accounting Change .............................. $ 1.89 $ 2.82 $ 2.69 $ 2.50 $ 1.82
Diluted Earnings per Share of Common Stock:
Before Discontinued Operations, Extraordinary Item
and Cumulative Effect of Accounting Change ..... $ 2.18 $ 2.84 $ 2.69 $ 2.50 $ 1.95
After Discontinued Operations, Extraordinary
Item and Cumulative
Effect of Accounting Change .................... $ 1.88 $ 2.81 $ 2.69 $ 2.50 $ 1.82
Dividends Declared per Share of Common Stock ........ $ 1.50 $ 1.50 $ 1.50 $ 1.50 $ 1.50
----------- ----------- ----------- ----------- -----------
Total Assets ........................................ $34,386,353 $37,351,513 $17,941,294 $18,224,047 $18,192,177
----------- ----------- ----------- ----------- -----------
Capitalization at December 31:
Common Stockholders' Equity ...................... $ 7,050,661 $ 7,398,599 $ 4,653,126 $ 4,563,890 $ 4,449,158
Preferred Stock:
Not Subject to Mandatory Redemption ............ 335,123 480,194 648,395 648,395 660,195
Subject to Mandatory Redemption ................ 428,388 594,856 161,105 256,246 294,710
Long-Term Debt* .................................. 10,872,216 12,865,352 5,742,048 6,001,264 6,352,359
----------- ----------- ----------- ----------- -----------
Total Capitalization* .......................... $18,686,388 $21,339,001 $11,204,674 $11,469,795 $11,756,422
=========== =========== =========== =========== ===========
* 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.
PRICE RANGE OF COMMON STOCK
The Common Stock of FirstEnergy Corp. is listed on the New York
Stock Exchange under the symbol "FE" and is traded on other registered
exchanges.
2002 2001
------------------ ------------------
First Quarter High-Low ......... $39.12 $30.30 $31.75 $25.10
Second Quarter High-Low ........ 35.12 31.61 32.20 26.80
Third Quarter High-Low ......... 34.78 24.85 36.28 29.60
Fourth Quarter High-Low ........ 33.85 25.60 36.98 32.85
Yearly High-Low ................ 39.12 24.85 36.98 25.10
Prices are based on reports published in The Wall Street Journal for New York
Stock Exchange Composite Transactions.
HOLDERS OF COMMON STOCK
There were 163,423 and 162,762 holders of 297,636,276 shares of
FirstEnergy's Common Stock as of December 31, 2002 and January 31, 2003,
respectively. Information regarding retained earnings available for payment of
cash dividends is given in Note 5A.
4
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. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), availability
and cost of capital, inability of the Davis-Besse Nuclear Power Station to
restart (including because of an inability to obtain a favorable final
determination from the Nuclear Regulatory Commission) in the fall of 2003,
inability to accomplish or realize anticipated benefits from strategic goals,
further investigation into the causes of the August 14, 2003, power outage and
other similar factors.
FirstEnergy Corp. is a registered public utility 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 planned but not pending for all 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) - providing electric distribution and
transmission services to portions of Pennsylvania and New Jersey. The
coordinated delivery of energy and energy-related products, including
electricity, natural gas and energy management services, to customers in
competitive 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 (FSG) and MARBEL Energy Corporation. Following
the GPU merger, competitive services are also provided through MYR Group, Inc.
RESTATEMENTS
As further discussed in Note 2(M) to the Consolidated Financial
Statements, the Company is restating its consolidated financial statements for
the year ended December 31, 2002. The revisions principally reflect a change in
the method of amortizing the costs being recovered under the Ohio transition
plan and recognition of above-market values of certain leased generation
facilities.
Transition Cost Amortization
As discussed under Regulatory matters in Note 2(D), FirstEnergy's
Ohio electric utilities recover transition costs, including regulatory assets,
through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2006 for OE,
2007 for TE and in 2009 for CEI.
FirstEnergy, OE, CEI and TE amortize these transition costs using
the effective interest method. The amortization schedules originally developed
at the beginning of the transition plan in 2001 in applying this method were
based on total transition revenues, including revenues designed to recover costs
which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments), but not in
the financial statements prepared under generally accepted accounting principles
(GAAP). The Ohio electric utilities have revised their amortization schedules
under the effective interest method to consider only revenues relating to
transition regulatory assets recognized on the GAAP balance sheet. The impact of
this change will result in higher amortization of these regulatory assets in the
first several years of the transition cost recovery period, compared with the
method previously applied. The change in method results in no change in total
amortization of the regulatory assets recovered under the transition period
through the end of 2009.
5
After giving effect to the restatement, total transition cost
amortization including above market leases) is expected to approximate the
following for the years from 2003 through 2009 (in millions).
2003 $685
2004 786
2005 913
2006 378
2007 213
2008 163
2009 44
Above-Market Lease Costs
In 1997, FirstEnergy was formed through a merger between OE and
Centerior Energy Corporation. The merger was accounted for as an acquisition of
Centerior, the parent company of CEI and TE, under the purchase accounting rules
of Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above-market lease
liabilities should have been recorded at the time of the merger. Accordingly, in
2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above March 1 market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which
CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE
recorded an increase in goodwill related to the above March 1 market lease costs
for Beaver Valley Unit 2 since regulatory accounting for nuclear generating
assets had been discontinued prior to the merger date and it was determined that
this additional liability would have increased goodwill at the date of the
merger. The corresponding impact of the above March 1 market lease liability for
the Bruce Mansfield Plant were recorded as regulatory assets because regulatory
accounting had not been discontinued at that time for the fossil generating
assets and recovery of these liabilities was provided under the transition plan.
The total above-market lease obligation of $722 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017 (approximately $37 million per year). The additional goodwill has been
recorded on a net basis, reflecting amortization that would have been recorded
through 2001, when goodwill amortization ceased with the adoption of Statement
of Financial Accounting Standard No.SFAS) 142, "Goodwill and Other Intangible
Assets". The total above-market lease obligation of $755 million associated with
the Bruce Mansfield Plant is being amortized through the end of 2016
(approximately $48 million per year). Before the start of the transition plan in
2001, the regulatory asset would have been amortized at the same rate as the
lease obligation resulting in no impact to net income. Beginning in 2001, the
remaining unamortized regulatory asset would have been included in CEI's and
TE's amortization schedules for regulatory assets and amortized through the end
of the recovery period - approximately 2009 for CEI and 2007 for TE.
FirstEnergy has reflected the net impact of the accounting for these
items for the period from the merger in 1997 through 2001 in the 2002 financial
statements. The cumulative impact to net income recorded in 2002 related to
these prior periods increased net income by $5.9 million in the restated 2002
financial statements and is reflected as a reduction in other operating expenses
in the accompanying consolidated statement of income. In addition, the impact
increased the following balances in the consolidated balance sheet as of January
1, 2002:
6
INCREASE (DECREASE) (IN THOUSANDS)
Goodwill............................ $ 381,780
Regulatory assets................... 636,100
----------
Total assets........................ $1,017,880
==========
Other current liabilities........... 84,600
Deferred income taxes............... (262,580)
Deferred investment tax credits..... (828)
Other deferred credits.............. 1,190,800
----------
Total liabilities................... $1,011,992
==========
Retained earnings................... $ 5,888
==========
The after-tax effect of the actual 2002 impact of these items
decreased net income for the year ended December 31, 2002, by $71 million, or
$0.24 per share. The effects of these changes on the Consolidated Statement of
Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows
previously reported for December 31, 2002 are described in Note 2(M) to the
Consolidated Financial Statements.
The adjustments described above are anticipated to result in a
decrease in reported net income through 2005 and an increase in net income for
the period 2006 through 2017, the end of the lease term for Beaver Valley Unit
2. The schedule below shows the estimated impact on net income of these
adjustments for 2003 through 2008.
CHANGE IN REGULATORY LEASE EFFECT ON EFFECT
TRANSITION COST ASSET LIABILITY PRE-TAX ON NET
YEAR AMORTIZATION AMORTIZATION (A) REVERSAL INCOME INCOME
- ---- ------------ ---------------- -------- ------ ------
(in millions)
2003 $(68) $(103) $85 $(86) $(51)
2004 (40) (118) 85 (73) (43)
2005 36 (136) 85 (16) (9)
2006 33 (83) 85 35 20
2007 64 (77) 85 72 43
2008 106 (56) 85 135 80
(a) This represents the additional amortization related to the regulatory
assets recognized in connection with the above-market lease for the Bruce
Mansfield Plant discussed above.
Other Adjustments -
FirstEnergy has also included in this restatement certain immaterial
adjustments that were not previously recognized in 2002 related to the
recognition of a valuation allowance on a tax benefit recognized in 2002 and
other adjustments. The impact of these adjustments decreased net income by $11.3
million.
The total after-tax effect of the adjustments in this restatement
decreased net income for the year ended December 31, 2002, by $76 million, or
$0.26 per share as shown below.
INCOME STATEMENT EFFECTS
- ------------------------
INCREASE (DECREASE) TRANSITION REVERSAL
COST OF LEASE TOTAL
AMORTIZATION OBLIGATIONS OTHER ADJUSTMENTS
------------ ----------- -------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Total revenues ............................ $ -- $ -- $ -- $ --
Fuel and purchased power .................. -- -- (10,700) (10,700)
Other operating expenses .................. -- (90,688) 14,800 75,888
Provision for depreciation and amortization 150,474 50,272 -- 200,746
------------ ----------- -------- -----------
Income before interest and income taxes ... 150,474 40,416 (4,100) 114,158
Net interest charges ...................... -- -- (3,300) (3,300)
Income taxes .............................. (30,920) (13,962) 10,500 (34,382)
------------ ----------- -------- -----------
Net income effect ......................... $ 119,554 $ 54,378 $(11,300) $ 76,476
============ =========== ======== ===========
Basic earnings per share effect ........... $ (0.42) $ 0.20 $ (0.04) $ (0.26)
============ =========== ======== ===========
Diluted earnings per share effect $ (0.42) $ 0.20 $ (0.04) $ (0.26)
============ =========== ======== ===========
7
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 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, our financial statements for 2001 reflect twelve months of operations
for our pre-merger organization and seven weeks of operations (November 7, 2001
to December 31, 2001) for the former GPU companies. In 2002, our financial
statements include twelve months of operations for both our pre-merger
organization and 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 Significant Accounting Policies -
Goodwill). As a result of the merger, we issued nearly 73.7 million shares of
our common stock, which are reflected in the calculation of earnings per share
of common stock in 2002 and for the seven-week period outstanding in 2001.
RESULTS OF OPERATIONS
Net income decreased to $552.8 million in 2002, compared to $646.4
million in 2001 and $599.0 million in 2000. Net income in 2001 included the
cumulative effect of an accounting change resulting in a net after-tax charge of
$8.5 million (see Cumulative Effect of Accounting Changes). Excluding the former
GPU companies' results (and related interest expense on acquisition debt), net
income decreased to $404.2 million in 2002 from $615.5 million in 2001 due in
large part to the incremental costs related to the extended Davis-Besse outage
and a number of one-time charges summarized in the table below. In addition,
SFAS 142, implemented January 1, 2002, resulted in the cessation of goodwill
amortization. In 2001, amortization of goodwill reduced net income by
approximately $57 million ($0.25 per share of common stock). Excluding the
former GPU companies' results (and related interest expense on acquisition
debt), net income increased in 2001 due to reduced depreciation and
amortization, general taxes and net interest charges. The benefits of these
reductions were offset in part by lower retail electric sales, increased other
operating expenses and higher gas costs.
Incremental costs related to the extended outage at the Davis-Besse
nuclear plant (see Davis-Besse Restoration) reduced basic and diluted earnings
per share of common stock by $0.47 in 2002. In addition, the table below
displays one-time charges that resulted in a comparative net reduction to basic
and diluted earnings of $0.46 per share of common stock in 2002, compared to
2001.
Previously reported variances of revenues, expenses, income taxes
and net income between 2001 as compared to 2000 included in Results of
Operations - Business Segments have been reclassified as a result of segment
information reclassifications (see Note 8 for additional discussion). In
addition, previously reported comparisons of sales of electricity between 2001
as compared to 2000 have also been reclassified as a result of adoption of
Emerging Issues Task Force (EITF) Issue No. 02-03, "Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities" (see Implementation
of Recent Accounting Standard for additional disclosure).
The impact of domestic and world economic conditions on the electric
power industry limited our divestiture program during 2002. By the end of 2001,
we had successfully completed the sale of our Australian gas transmission
companies, had reached agreement with Aquila, Inc. for the sale of our holdings
of electric distribution facilities in the United Kingdom (UK) and executed an
agreement with NRG Energy Inc. (NRG) for the sale of four coal-fired power
plants. However, the UK transaction with Aquila closed on May 8, 2002 and
reflected the March 2002 modification of Aquila's initial offer such that Aquila
acquired a 79.9 percent equity interest in Avon Energy Partners Holdings (Avon)
for approximately $1.9 billion (including the assumption of $1.7 billion of
debt). In the fourth quarter of 2002, we recognized a $50 million impairment of
our Avon investment. On August 8, 2002, we notified NRG that we were canceling
our agreement with them for their purchase of the four fossil plants because NRG
had stated that it could not complete the transaction under the original terms
of the agreement. We were also actively pursuing the sale of an electric
distribution company in Argentina - GPU Empressa Distribuidora Electrica
Regional S.A. and its affiliates (Emdersa). With the deteriorating economic
conditions in Argentina no sale could be completed by December 31, 2002. (See
Note 3 regarding the April 2003 abandonment). Further information on the impact
of the changes in accounting related to our divestiture activities is available
in the "Change in Previously Reported Income Statement Classifications" section
and in the discussion of depreciation charges in the "Expenses" section below.
One-time pre-tax charges to earnings before the cumulative effect of
accounting change are summarized in the following table:
8
ONE-TIME CHARGES
2002 2001 CHANGE
------ ------ ------
(IN MILLIONS)
Investment impairments................................... $100.7 -- $100.7
Pennsylvania deferred energy costs....................... 55.8 -- 55.8
Avon and Emdersa adjustment.............................. 61.0 -- 43.5
Lake Plants - depreciation and sale costs................ 29.2 -- 29.2
Long-term derivative contract adjustment................. 18.1 -- 18.1
Generation project cancellation.......................... 17.1 -- 17.1
Severance costs - 2002................................... 11.3 -- 11.3
Uncollectible reserve and contract losses................ -- 9.2 (9.2)
Early retirement costs - 2001............................ -- 8.8 (8.8)
Estimated claim settlement............................... 16.8 -- 16.8
------ ------ ------
.......................................................... $310.0 $ 18.0 $274.5
====== ====== ======
REDUCTION TO EARNINGS PER SHARE OF COMMON STOCK
BASIC.................................................. $ 0.76 $ 0.05 $0.65
====== ====== ======
DILUTED................................................ $ 0.76 $ 0.05 $0.65
====== ====== ======
Revenues
Total revenues increased $4.2 billion in 2002, which included more
than $4.6 billion incremental revenues for the former GPU companies in 2002
(twelve months), compared to 2001 (seven weeks). Excluding results from the
former GPU companies, total revenues increased $24.7 million following a $336.7
million increase in 2001. The additional sales in both years 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 2002 and 2001, compared to
the prior year, are summarized in the following table:
9
SOURCES OF REVENUE CHANGES 2002 2001
- -------------------------- -------- --------
INCREASE (DECREASE) (IN MILLIONS)
Pre-Merger Companies:
Electric Utilities (Regulated Services):
Retail electric sales .............................. $ (328.5) $ (240.5)
Other revenues ..................................... 18.4 (22.6)
-------- --------
Total Electric Utilities ............................. (310.1) (263.1)
-------- --------
Unregulated Businesses (Competitive Services):
Retail electric sales .............................. 136.4 (19.9)
Wholesale electric sales:
Nonaffiliated .................................... 140.0 254.4
Affiliated ....................................... 345.3 32.7
Gas sales .......................................... (171.7) 226.1
Other revenues ..................................... (115.2) 106.5
-------- --------
Total Unregulated Businesses ......................... 334.8 599.8
-------- --------
Total Pre-Merger Companies ........................... 24.7 336.7
-------- --------
Former GPU Companies:
Electric utilities ................................. 3,782.4 570.4
Unregulated businesses ............................. 766.0 101.9
-------- --------
Total Former GPU Companies ........................... 4,548.4 672.3
Intercompany Revenues ................................ (341.9) (38.6)
-------- --------
Net Revenue Increase ................................. $4,231.2 $ 970.4
======== ========
Electric Sales
Shopping by Ohio customers for alternative energy suppliers combined
with the effect of a sluggish national economy on regional business reduced
retail electric sales revenues of our pre-merger EUOCs by $328.5 million (or
7.1%) in 2002 compared to 2001. Since Ohio opened its retail electric market to
competing generation suppliers in 2001, sales of electric generation by
alternative suppliers in our franchise areas have risen steadily, providing
23.6% of total energy delivered to retail customers in 2002, compared to 11.3%
in 2001. As a result, generation kilowatt-hour sales to retail customers by the
EUOC were 14.2% lower in 2002 than the prior year, which reduced regulated
retail electric sales revenues by $230.6 million.
Revenue from distribution deliveries decreased by $11.7 million in
2002 compared to 2001. KWH deliveries to franchise customers were 0.5% lower in
2002 compared to the prior year. The decrease resulted from the net effect of a
6.3% increase in kilowatt-hour deliveries to residential customers (due in large
part to warmer summer weather in 2002) offset by a 3.2% decline in kilowatt-hour
deliveries to commercial and industrial customers as a result of sluggish
economic conditions.
The remaining decrease in regulated retail electric sales revenues
resulted from additional transition plan incentives provided to customers to
promote customer shopping for alternative suppliers - $86.0 million of
additional credits in 2002 compared to 2001. These reductions to revenue are
deferred for future recovery under our Ohio transition plan and do not
materially affect current period earnings.
Despite the decrease in kilowatt-hour sales by our pre-merger EUOC,
total electric generation sales increased by 22.0% in 2002 compared to the prior
year as a result of higher kilowatt-hour sales by our competitive services
segment. Revenues from the wholesale market increased $501.4 million in 2002
from 2001 and kilowatt-hour sales more than doubled. More than half of the
increase resulted from additional affiliated company sales by FES to Met-Ed and
Penelec. FES assumed the supply obligation in the third quarter of 2002 for a
portion of Met-Ed's and Penelec's provider of last resort (PLR) supply
requirements (see State Regulatory Matters - Pennsylvania). The increase also
included sales into the New Jersey market as an alternative supplier for a
portion of New Jersey's basic generation service (BGS). Retail sales by our
competitive services segment increased by $136.4 million as a result of a 59.0%
increase in kilowatt-hour sales in 2002 from 2001. That increase resulted from
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 retail sales in markets outside of Ohio.
In 2001, our pre-merger EUOC retail revenues decreased by $240.5
million compared to 2000, principally due to lower generation sales volume
resulting from the first year of customer choice in Ohio. Sales by alternative
suppliers increased to 11.3% of total energy delivered compared to 0.8% in 2000.
Implementation of a 5% reduction in generation
10
charges for residential customers as part of Ohio's electric utility
restructuring in 2001 also contributed $51.2 million to the reduced electric
sales revenues. 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 2.7% in 2001 compared
to the prior year with sales to the wholesale market being the largest single
factor contributing to this increase. Kilowatt-hour sales to wholesale customers
more than doubled from 2000 and revenues increased $287.1 million in 2001 from
the prior year. The higher kilowatt-hour sales benefited from increased
availability of power to sell into the wholesale market, due to additional
internal generation and increased shopping by retail customers from alternative
suppliers, which allowed us to take advantage of wholesale market opportunities.
Retail kilowatt-hour sales by our competitive services segment increased by 3.6%
in 2001, compared to 2000, primarily due to expanding sales within Ohio as a
result of retail customers switching to FES 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 some customers returned to their local
distribution companies. Despite an increase in kilowatt-hour sales in Ohio's
competitive market, declining sales to higher-priced eastern markets contributed
to an overall decline in retail competitive sales revenue in 2001 from the prior
year.
Changes in electric generation sales and distribution deliveries in
2002 and 2001 for our pre-merger companies are summarized in the following
table:
CHANGES IN KWH SALES 2002 2001
- -------------------- ------ ------
INCREASE (DECREASE)
Electric Generation Sales:
Retail -
Regulated services ................................ (14.2)% (12.2)%
Competitive services .............................. 59.0% 3.6%
Wholesale ........................................... 122.6% 117.2%
------ ------
Total Electric Generation Sales ...................... 22.0% 2.7%
====== ======
EUOC Distribution Deliveries:
Residential ......................................... 6.3% 1.7%
Commercial and industrial ........................... (3.2)% (3.1)%
------ ------
Total Distribution Deliveries ........................ (0.5)% (1.7)%
====== ======
Our regulated and unregulated subsidiaries record purchase and sales
transactions with PJM Interconnection ISO, an independent system operator, on a
gross basis in accordance with Emerging Issues Task Force (EITF) Issue No.
99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This
gross basis classification of revenues and costs may not be comparable to other
energy companies that operate in regions that have not established ISOs and do
not meet EITF 99-19 criteria.
11
The aggregate purchase and sales transactions for the three years
ended December 31, 2002, are summarized as follows:
2002 2001 2000
---- ---- ----
(IN MILLIONS)
Sales $453 $142 $315
Purchases 687 204 271
---- ---- ----
FirstEnergy's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from the PJM ISO from power sales
(as reflected in the table above) during periods when we had additional
available power capacity. Revenues also include sales by FirstEnergy of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when we required additional power to meet our retail load requirements
and, secondarily, to sell in the wholesale market.
Nonelectric Sales
Nonelectric sales revenues declined by $284.6 million in 2002 from
2001. The elimination of coal trading activities in the second half of 2001 and
reduced natural gas sales were the primary factors contributing to the lower
revenues. Reduced gas revenues resulted principally from lower prices compared
to 2001. Despite a slight reduction in sales volume and lower prices in 2002,
margins from gas sales improved (see Expenses below). Reduced revenues from the
facilities services group also contributed to the decrease in other sales
revenue in 2002, compared to 2001. In 2001, nonelectric revenues increased
$332.6 million, with natural gas revenues providing the largest source of
increase. Beginning November 1, 2000, residential and small business customers
in the service area of a nonaffiliated gas utility began shopping among
alternative gas suppliers as part of a customer choice program. FES's ability to
take advantage of this opportunity to expand its customer base contributed to
the increase in natural gas revenues.
Expenses
Total expenses increased nearly $3.8 billion in 2002, which included
more than $3.7 billion of incremental expenses for the former GPU companies in
2002 (twelve months), compared to 2001 (seven weeks). For our pre-merger
companies, total expenses increased $409.9 million in 2002 and $280.4 million in
2001, compared to the respective prior years. Sources of changes in pre-merger
and post-merger companies' expenses in 2002 and 2001, compared to the prior
year, are summarized in the following table:
SOURCES OF EXPENSE CHANGES 2002 2001
- ------------------------------- -------- --------
INCREASE (DECREASE) (IN MILLIONS)
PRE-MERGER COMPANIES:
Fuel and purchased power $ 431.0 $ 48.7
Purchased gas (227.9) 266.5
Other operating expenses 102.6 178.2
Depreciation and amortization 75.6 (99.0)
General taxes 28.5 (114.0)
-------- --------
TOTAL PRE-MERGER COMPANIES 409.9 280.4
-------- --------
FORMER GPU COMPANIES 3,730.0 542.4
INTERCOMPANY EXPENSES (353.9) (32.6)
-------- --------
NET EXPENSE INCREASE $3,785.9 $ 790.2
======== ========
The following comparisons reflect variances for the pre-merger
companies only, excluding the incremental expenses for the former GPU companies
in 2002 and 2001.
Higher fuel and purchased power costs in 2002 compared to 2001
primarily reflect additional purchased power costs of $352.9 million. The
increase resulted from additional volumes to cover supply obligations assumed by
FES. These included a portion of Met-Ed's and Penelec's PLR supply requirements
(which started in the third quarter of 2002), contract sales including sales to
the New Jersey market to provide BGS, and additional supplies required to
replace Davis-Besse power during its extended outage (see Davis-Besse
Restoration). Fuel expense increased $99.5 million in 2002 from the prior year
principally due to additional internal generation (5.4% higher) and an increased
mix of coal and natural gas generation in 2002. The extended outage at the
Davis-Besse nuclear plant produced a decline in nuclear generation of 14.6% in
2002, compared to 2001. Purchased gas costs decreased by $227.9 million
primarily due to lower unit costs of natural gas purchased in 2002 compared to
the prior year resulting in a $48.4 million improvement in gas margins.
12
In 2001, the increase in fuel expense compared to 2000 ($24.3
million) resulted from the substitution of coal and natural gas fired generation
for nuclear generation during a period of reduced nuclear availability resulting
from both planned and unplanned outages. Higher unit costs for coal consumed
also contributed to the increase 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 as a result of
generally lower prices and reduced external power needs compared to 2000.
Purchased gas costs increased 48% in 2001 compared to 2000, principally due to
the expansion of FES's retail gas business.
Other operating expenses increased $102.6 million in 2002 from the
previous year. The increase principally resulted from several large offsetting
factors. Nuclear costs increased $125.3 million primarily due to $115.0 million
of incremental Davis-Besse costs related to its extended outage (see Davis-Besse
Restoration). One-time charges, discussed above, added $98.3 million and an
aggregate increase in administrative and general expenses and non-operating
costs of $127.4 million resulted in large part from higher employee benefit
expenses. Partially offsetting these higher costs were the elimination in the
second half of 2001 of coal trading activities ($95.4 million) and reduced
facilities service business ($58.9 million). The reversal of lease obligations
related to the Bruce Mansfield fossil facility and Beaver Valley nuclear
facility reduced other operating expenses by $84.8 million in 2002 as compared
to 2001.
In 2001, other operating expenses increased by $178.2 million
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 2000, resulting from one less refueling
outage.
Fossil operating costs increased $44.3 million in 2001 from 2000 due
principally to planned maintenance work at the Bruce Mansfield generating plant.
Pension costs increased by $32.6 million in 2001 from 2000 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.
Charges for depreciation and amortization increased $75.6 million in
2002 from the preceding year. This increase resulted from several factors:
increased amortization under the Ohio transition plan ($201 million). The start
up of a new fluidized bed boiler in January 2002, owned by Bayshore Power
Company, a wholly owned subsidiary, resulted in higher depreciation expense in
2002. Also, new combustion turbine capacity added in late 2001 and two months of
2001 depreciation recorded in 2002 (for the four fossil plants we chose not to
sell) increased depreciation expense in 2002. However, two factors offset a
portion of the above increase: shopping incentive deferrals and tax-deferrals
under the Ohio transition plan ($108.5 million) and the cessation of goodwill
amortization ($56.4 million) beginning January 1, 2002.
In 2001, charges for depreciation and amortization decreased by
$99.0 million from the prior year. Approximately $64.6 million of the decrease
resulted from lower incremental transition cost amortization under our 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 completed combustion turbines in the fourth quarter of 2001.
General taxes increased $28.5 million in 2002 from 2001 principally
due to additional property taxes and the absence in 2002 of a one-time benefit
of $15 million resulting from the successful resolution of certain property tax
issues in the prior year. In 2001, general taxes declined $114.0 million from
2000 primarily due to reduced property taxes and other state tax changes in
connection with the Ohio electric industry restructuring. 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 $406.6 million in 2002, compared to
2001. These increases included interest on $4 billion of long-term debt issued
by FirstEnergy in connection with the merger. Excluding the results associated
with the former GPU companies and merger-related financing, net interest charges
decreased $57.0 million in 2002, compared to a $39.8 million decrease in 2001
from 2000. Our continued redemption and refinancing of our outstanding debt and
preferred stock during 2002, maintained our downward trend in financing costs,
before the effects of the GPU merger. Excluding activities related to the former
GPU companies, redemption and refinancing activities for 2002 totaled $1.1
billion and $143.4 million, respectively, and are expected to result in
annualized savings of $86.0 million. We also exchanged existing fixed-rate
payments on outstanding debt (principal amount of $593.5 million at year end
2002) for
13
short-term variable rate payments through interest rate swap transactions (see
Market Risk Information - Interest Rate Swap Agreements below). Net interest
charges were reduced by $17.4 million in 2002 as a result of these swaps.
Discontinued Operations
In April 2003, FirstEnergy divested its ownership in GPU Empresa
Distribuidora Electrica Regional S.A. and affiliates (Emdersa) through the
abandonment of its shares in the parent company of the Argentina operation.
FirstEnergy has reclassified the results of Emdersa for the year ended December
31, 2002, totaling $87.5 million in discontinued operations.
Cumulative Effect of Accounting Change
In 2001, we adopted SFAS 133, "Accounting for Derivative Instruments
and Hedging Activities" resulting in an $8.5 million after-tax charge. (See Note
2J)
Postretirement Plans
Sharp declines in equity markets since the second quarter of 2000
and a reduction in our assumed discount rate in 2001 have combined to produce a
negative trend in pension expenses - moving from a net increase to earnings in
2000 and 2001 to a reduction of earnings in 2002. Also, increases in health care
payments and a related increase in projected trend rates have led to higher
health care costs. The following table presents the pre-tax pension and other
post-employment benefits (OPEB) expenses for our pre-merger companies (excluding
amounts capitalized):
POSTRETIREMENT EXPENSES (INCOME) 2002 2001 2000
- -------------------------------- ------ ------ ------
(IN MILLIONS)
Pension $ 16.4 $(11.1) $(40.6)
OPEB 99.1 86.6 65.5
------ ------ ------
Total $115.5 $ 75.5 $ 24.9
====== ====== ======
The pension and OPEB expense increases are included in various cost
categories and have contributed to other cost increases discussed above. See
"Significant Accounting Policies - Pension and Other Postretirement Benefits
Accounting" for a discussion of the impact of underlying assumptions on
postretirement expenses and anticipated pension and OPEB expense increases in
2003.
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 competitive 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 8 to the consolidated
financial statements. Financial data for 2002 and 2001 for the major business
segments include reclassifications to conform with the current business segment
organizations and operations, which affect 2002 and 2001 results discussed
below.
Regulated Services
Net income increased to $938 million in 2002, compared to $729.1
million in 2001 and $562.5 million in 2000. Excluding additional net income of
$312.7 million associated with the former GPU companies, net income decreased by
$103.7 million in 2002. The changes in pre-merger net income are summarized in
the following table:
REGULATED SERVICES 2002 2001
- ------------------ ------- -------
INCREASE (DECREASE) (IN MILLIONS)
Revenues $(529.5) $(116.4)
Expenses (232.4) (344.1)
------- -------
Income Before Interest and Income Taxes (297.1) 227.7
------- -------
Net interest charges (131.3) (16.8)
Income taxes (62.1) 132.7
------- -------
Net Income Change $(103.7) $ 111.8
======= =======
Lower generation sales, additional transition plan incentives and a
slight decline in revenue from distribution deliveries combined for a $312.5
million reduction in external revenues in 2002 from the prior year. Shopping by
Ohio customers from alternative energy suppliers combined with the effect of a
sluggish national economy on our regional
14
business reduced retail electric sales revenues. In addition, a $188.0 million
decline in revenues resulted from reduced sales to FES, due to the extended
outage of the Davis-Besse nuclear plant, which reduced generation available for
sale. The $232.4 million decrease in expenses primarily resulted from three
major factors: a $190.5 million decrease in purchased power, a $111.6 million
reduction in other operating expenses and a $58.9 million increase in
depreciation expense. Lower generation sales reduced the need for purchased
power and other operating expenses reflected reduced costs in jobbing and
contracting work and decreased uncollectible accounts expense. Higher
depreciation and amortization resulted from $201 million higher incremental
transition costs partially offset by $108.5 million of new deferred regulatory
assets under the Ohio transition plan and the cessation of goodwill amortization
beginning January 1, 2002.
In 2001, distribution throughput was 1.7% lower, 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
$116.4 million reduction to total revenues. Expenses were $344.1 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
$267.8 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 our Ohio transition 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.
Competitive Services
Net losses increased to $119.0 million in 2002, compared to $31.8
million in 2001 and net income of $39.1 million in 2000. Excluding additional
net income of $2.6 million associated with the former GPU companies, net losses
increased by $89.8 million in 2002. The changes to pre-merger earnings are
summarized in the following table:
COMPETITIVE SERVICES 2002 2001
- -------------------- ------ ------
INCREASE (DECREASE) (IN MILLIONS)
Revenues $211.5 $289.3
Expenses 351.1 392.5
------ ------
Income Before Interest and Income Taxes (139.6) (103.2)
------ ------
Net interest charges 21.9 13.5
Income taxes (63.2) (51.3)
Cumulative effect of a change in accounting 8.5 (8.5)
------ ------
Net Loss Increase $ 89.8 $ 73.9
====== ======
The $211.5 million increase in revenues in 2002, compared to 2001,
represents the net effect of several factors. Revenues from the wholesale
electricity market increased $485.3 million in 2002 from the prior year and KWH
sales more than doubled. More than half of the increase resulted from additional
sales to Met-Ed and Penelec to supply a portion of their PLR supply requirements
in Pennsylvania, as well as BGS sales in New Jersey and sales under several
other contracts. Retail KWH sales revenues increased $136.4 million as a result
of expanding KWH sales within Ohio under Ohio's electricity choice program.
Total electric sales revenue increased $621.7 million in 2002 from 2001,
accounting for almost all of the net increase in revenues. Offsetting the higher
electric sales revenue were reduced natural gas revenues ($171.7 million)
primarily due to lower prices and less revenue from FSG ($65.5 million)
reflecting the sluggish economy. Internal sales to the regulated services
segment decreased $179.8 million in large part due to the impact of customer
shopping reducing requirements by the regulated services segment. Expenses
increased $351.1 million in 2002 from the prior year, due to additional
purchased power ($342.2 million) to supply the incremental KWH sales to
wholesale and retail customers. Other operating expenses increased $207.2
million from the prior year as a result of higher nuclear costs due to
incremental Davis-Besse costs from its extended outage. One-time charges
discussed above increased costs by $75.6 million. Offsetting these increases
were reduced purchased gas costs ($227.9 million) primarily resulting from lower
prices and reduced costs from FSG reflecting reduced business activity.
In 2001, sales to nonaffiliates increased $523.2 million, compared
to the prior year, with electric revenues contributing $299.8 million, natural
gas revenues adding $226.1 million and the balance of the change from
energy-related services. Reduced power requirements by the regulated services
segment reduced internal revenues by $267.8 million. Expenses increased $392.5
million in 2002 from 2001 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 above) as well
15
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.
CAPITAL RESOURCES AND LIQUIDITY
Changes in Cash Position
The primary source of ongoing cash for FirstEnergy, as a holding
company, is cash dividends from its subsidiaries. The holding company also has
access to $1.5 billion of revolving credit facilities, which it can draw upon.
In 2002, FirstEnergy received $447 million of cash dividends on common stock
from its subsidiaries and paid $440 million in cash dividends on common stock to
its shareholders. There are no material restrictions on the issuance of cash
dividends by FirstEnergy's subsidiaries.
As of December 31, 2002, we had $196.3 million of cash and cash
equivalents (including $50 million that redeemed long-term debt in January 2003)
on our Consolidated Balance Sheet. This compares to $220.2 million as of
December 31, 2001. The major sources for changes in these balances are
summarized below.
Cash Flows From Operating Activities
Our consolidated net cash from operating activities is provided by
our regulated and competitive energy services businesses (see Results of
Operations - Business Segments above). Net cash flows from operating activities
in 2002 reflect twelve months of cash flows for the former GPU companies while
2001 includes only seven weeks of those companies' operations (November 7, 2001
to December 31, 2001). Both periods include a full twelve months for the
pre-merger companies. Net cash provided from operating activities was $1.915
billion in 2002 and $1.282 billion in 2001. The modest contribution to operating
cash flows in 2002 by the former GPU companies reflects in part the deferrals of
purchased power costs related to their PLR obligations (see State Regulatory
Matters - New Jersey and Pennsylvania below). Cash flows provided from 2002
operating activities of our pre-merger companies and former GPU companies are as
follows:
OPERATING CASH FLOWS 2002 2001
- --------------------------- ------- -------
(IN MILLIONS)
Pre-merger Companies:
Cash earnings (1) $ 1,059 $ 1,551
Working capital and other 405 21
------- -------
Total pre-merger companies 1,464 1,572
Former GPU companies 563 166
Eliminations (112) (456)
------- -------
Total $ 1,915 $ 1,282
======= =======
(1) Includes net income, depreciation and amortization, deferred costs
recoverable as regulatory assets, deferred income taxes, investment tax
credits and major noncash charges.
Excluding the former GPU companies, cash flows from operating
activities totaled $1.464 billion in 2002 primarily due to cash earnings and to
a lesser extent working capital and other changes. In 2001, cash flows from
operating activities totaled $1.572 billion principally due to cash earnings.
Cash Flows From Financing Activities
In 2002, the net cash used for financing activities of $1.123
billion primarily reflects the redemptions of debt and preferred stock shown
below. In 2001, net cash provided from financing activities totaled $1.964
billion, primarily due to $4 billion of long-term debt issued in connection with
the GPU acquisition, which was partially offset by $2.1 billion of redemptions
and refinancings. The following table provides details regarding new issues and
redemptions during 2002:
16
SECURITIES ISSUED OR REDEEMED 2002
- ----------------------------- -------
(IN MILLIONS)
New Issues
Pollution Control Notes $ 143
Transition Bonds (See Note 5H) 320
Unsecured Notes 210
Other, principally debt discounts (4)
-------
$ 669
Redemptions
First Mortgage Bonds $ 728
Pollution Control Notes 93
Secured Notes 278
Unsecured Notes 189
Preferred Stock 522
Other, principally redemption premiums 21
-------
$1,831
Short-term Borrowings, Net $ 479
-------
We had approximately $1.093 billion of short-term indebtedness at
the end of 2002 compared to $614.3 million at the end of 2001. Available
borrowing capability included $177 million under the $1.5 billion revolving
lines of credit and $64 million under bilateral bank facilities. At the end of
2002, OE, CEI, TE and Penn had the aggregate capability to issue $2.1 billion of
additional first mortgage bonds (FMB) on the basis of property additions and
retired bonds. JCP&L, Met-Ed and Penelec will no longer issue FMB other than as
collateral for senior notes, since their senior note indentures prohibit them
(subject to certain exceptions) from issuing any debt which is senior to the
senior notes. As of December 31, 2002, JCP&L, Met-Ed and Penelec had the
aggregate capability to issue $474 million of additional senior notes based upon
FMB collateral. Based upon applicable earnings coverage tests and their
respective charters, OE, Penn, TE and JCP&L could issue a total of $4.3 billion
of preferred stock (assuming no additional debt was issued) as of the end of
2002. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred
stock (see Note 5G - Long-Term Debt for discussion of debt covenants).
At the end of 2002, our common equity as a percentage of
capitalization stood at 38% compared to 35% and 42% at the end of 2001 and 2000,
respectively. The lower common equity percentage in 2002 compared to 2000
resulted from the effect of the GPU acquisition. The increase in the 2002 equity
percentage from 2001 primarily reflects net redemptions of preferred stock and
long-term debt, financed in part by short-term borrowings, and the increase in
retained earnings.
Cash Flows From Investing Activities
Net cash flows used in investing activities totaled $816 million in
2002. The net cash used for investing principally resulted from property
additions. Regulated services expenditures for property additions primarily
include expenditures supporting the distribution of electricity. Expenditures
for property additions by the competitive services segment are principally
generation-related including capital additions at the Davis-Besse nuclear plant
during its extended outage. The following table summarizes 2002 investments by
our regulated services and competitive services segments:
SUMMARY OF 2002 CASH FLOWS PROPERTY
USED FOR INVESTING ACTIVITIES ADDITIONS INVESTMENTS OTHER TOTAL
- ----------------------------- --------- ----------- ----- -----
SOURCES (USES) (IN MILLIONS)
Regulated Services $ (490) $ 87 $ (21) $(424)
Competitive Services (403) -- 10 (393)
Other (105) 149* (54) (10)
Eliminations -- -- 11 11
--------- ----------- ----- -----
Total $ (998) $ 236 $ (54) $(816)
========= =========== ===== =====
* Includes $155 million of cash proceeds from the sale of Avon (see Note 3).
In 2001, net cash flows used in investing activities totaled $3.075
billion, principally due to the GPU acquisition ($2.013 billion) and property
additions ($852 million).
Our cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
we expect to meet our contractual obligations with cash from operations.
Thereafter, we expect to use a combination of cash from operations and funds
from the capital markets.
17
LESS THAN 1-3 3-5 MORE THAN
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR YEARS YEARS 5 YEARS
- ----------------------- ------- ------- ------- ------- -------
(IN MILLIONS)
Long-term debt $12,465 $ 1,073 $ 2,210 $ 1,654 $ 7,528
Short-term borrowings 1,093 1,093 -- -- --
Preferred stock (1) 445 2 4 14 425
Capital leases (2) 31 5 11 7 8
Operating leases (2) 2,697 153 365 349 1,830
Purchases (3) 13,156 2,149 2,902 2,634 5,471
------- ------- ------- ------- -------
Total $29,887 $ 4,475 $ 5,492 $ 4,658 $15,262
======= ======= ======= ======= =======
(1) Subject to mandatory redemption
(2) See Note 4
(3) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing
Our capital spending for the period 2003-2007 is expected to be
about $3.1 billion (excluding nuclear fuel), of which approximately $727 million
applies to 2003. Investments for additional nuclear fuel during the 2003-2007
period are estimated to be approximately $485 million, of which about $69
million applies to 2003. During the same period, our nuclear fuel investments
are expected to be reduced by approximately $483 million and $88 million,
respectively, as the nuclear fuel is consumed.
In May 2002, we sold a 79.9 percent equity interest in Avon, our
former wholly owned holding company of Midlands Electricity plc, to Aquila, Inc.
(formerly UtiliCorp United) for approximately $1.9 billion (including assumption
of $1.7 billion of debt). We received approximately $155 million in cash
proceeds and approximately $87 million of long-term notes (representing the
present value of $19 million per year to be received over six years beginning in
2003). In the fourth quarter of 2002, we recorded a $50 million charge to reduce
the carrying value of our remaining Avon 20.1 percent equity investment. On
August 8, 2002, we notified NRG that we were canceling a November 2001 agreement
to sell four fossil plants for approximately $1.5 billion ($1.355 billion in
cash and $145 million in debt assumption) to NRG because NRG had stated it could
not complete the transaction under the original terms of the agreement. In
December 2002, we announced that we would retain ownership of the plants after
reviewing subsequent bids from other potential buyers. As a result of this
decision, we recorded an aggregate charge of $74 million ($43 million, net of
tax) in the fourth quarter of 2002, consisting of $57 million ($33 million, net
of tax) in non-cash depreciation charges that were not recorded while the plants
were pending sale and $17 million ($10 million, net of tax) of
transaction-related fees (see Note 3). in the 2001 merger with GPU. On April 18,
2003, we divested our ownership interest in Emdersa, our Argentina operations,
resulting in a charge of $87.5 million in the restated year ended December 31,
2002 Consolidated Statement of Income as "Discontinued Operations (See Note 2M).
On August 14, 2003, Moody's Investors Service placed the debt
ratings of FirstEnergy and all of its subsidiaries under review for possible
downgrade. Moody's stated that the review was prompted by: (1) weaker than
expected operating performance and cash flow generation; (2) less progress than
expected in reducing debt; (3) continuing high leverage relative to its peer
group; and (4) negative impact on cash flow and earnings from the continuing
nuclear plant outage at Davis-Besse. Moody's further stated that, in
anticipation of Davis-Besse returning to service in the near future and
FirstEnergy's continuing to significantly reduce debt and improve its financial
profile, "Moody's does not expect that the outcome of the review will result in
FirstEnergy's senior unsecured debt rating falling below investment-grade."
On July 25, 2003, Standard & Poor's (S&P) issued comments on
FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse
outage and the NJBPU decision on the JCP&L rate case. S&P noted that additional
costs from the Davis-Besse outage extension, the NJBPU ruling on recovery of
deferred energy costs and additional capital investments required to improve
reliability in the New Jersey shore communities will adversely affect
FirstEnergy's cash flow and deleveraging plans. S&P noted that it continues to
assess FirstEnergy's plans to determine if projected financial measures are
adequate to maintain its current rating.
On August 7, 2003, S&P affirmed its "BBB" corporate credit rating
for FirstEnergy. However, S&P stated that although FirstEnergy generates
substantial free cash, that its strategy for reducing debt had deviated
substantially from the one presented to S&P around the time of the GPU merger
when the current rating was assigned. S&P further noted that their affirmation
of FirstEnergy's corporate credit rating was based on the assumption that
FirstEnergy would take appropriate steps quickly to maintain its investment
grade ratings including the issuance of equity and possible sale of assets. Key
issues being monitored by S&P included reaudit of CEI and TE by
PricewaterhouseCoopers LLP, restart of Davis-Besse, FirstEnergy's liquidity
position, its ability to forecast provider-of-last-resort load and the
performance of its hedged portfolio, and capture of merger synergies.
18
OTHER OBLIGATIONS
Obligations not included on our Consolidated Balance Sheet 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 4). The present value as of December 31,
2002, 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 $170 million of off-balance sheet
financing as of December 31, 2002 (see Note 2 - Revenues).
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, we enter into various
agreements on behalf of our subsidiaries to provide financial or performance
assurances to third parties. Such agreements include contract guarantees, surety
bonds, and rating-contingent collateralization provisions.
As of December 31, 2002, the maximum potential future payments under
outstanding guarantees and other assurances totaled $913 million, as summarized
below:
MAXIMUM
GUARANTEES AND OTHER ASSURANCES EXPOSURE
- ------------------------------- --------
(IN MILLIONS)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts(1) $ 670
Financings (2)(3) 186
--------
856
Surety Bonds 26
Rating-Contingent Collateralization (4) 31
--------
Total Guarantees and Other Assurances $ 913
========
(1) Issued for a one-year term, with a 10-day termination right by
FirstEnergy.
(2) Includes parental guarantees of subsidiary debt and lease financing
including our letters of credit supporting subsidiary debt.
(3) Issued for various terms.
(4) Estimated net liability under contracts subject to rating-contingent
collateralization provisions.
We guarantee energy and energy-related payments of our subsidiaries
involved in energy marketing activities - principally to facilitate normal
physical transactions involving electricity, gas, emission allowances and coal.
We also provide guarantees to various providers of subsidiary financings
principally for the acquisition of property, plant and equipment. These
agreements legally obligate us and our subsidiaries to fulfill the obligations
of our subsidiaries directly involved in these energy and energy-related
transactions or financings where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, our guarantee enables the
counterparty's legal claim to be satisfied by our other assets. The likelihood
is remote that such parental guarantees will increase amounts otherwise paid by
us to meet our obligations incurred in connection with financings and ongoing
energy and energy-related contracts.
Most of our surety bonds are backed by various indemnities common
within the insurance industry. Surety bonds and related guarantees provide
additional assurance to outside parties that contractual and statutory
obligations will be met in a number of areas including construction contracts,
environmental commitments and various retail transactions.
Various contracts include credit enhancements in the form of cash
collateral, letters of credit or other security in the event of a reduction in
credit rating. These provisions vary and typically require more than one rating
reduction to below investment grade by S&P or Moody's to trigger additional
collateralization.
MARKET RISK INFORMATION
We use various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price and interest rate
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
19
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. Most of our non-hedge derivative contracts
represent non-trading positions that do not qualify for hedge treatment under
SFAS 133. The change in the fair value of commodity derivative contracts related
to energy production during 2002 is summarized in the following table:
INCREASE (DECREASE) IN THE FAIR VALUE
OF COMMODITY DERIVATIVE CONTRACTS
NON-HEDGE HEDGE TOTAL
--------- --------- ---------
(IN MILLIONS)
Outstanding net asset (liability) as of January 1, 2002 $ 9.9 $ (76.3) $ (66.4)
New contract value when entered -- 2.2 2.2
Additions/Increase in value of existing contracts 55.5 73.9 129.4
Change in techniques/assumptions (20.1) -- (20.1)
Settled contracts 8.5 24.3 32.8
--------- --------- ---------
Outstanding net asset as of December 31, 2002 (1) 53.8 24.1 77.9
--------- --------- ---------
NON-COMMODITY NET ASSETS AS OF DECEMBER 31, 2002:
Interest Rate Swaps (2) -- 20.5 20.5
--------- --------- ---------
NET ASSETS - DERIVATIVES CONTRACTS AS OF DECEMBER 31, 2002 (3) $ 53.8 $ 44.6 $ 98.4
========= ========= =========
Impact of Changes in Commodity Derivative Contracts (4)
Income Statement Effects (Pre-Tax) $ 13.9 $ -- $ 13.9
Balance Sheet Effects:
Other Comprehensive Income (OCI) (Pre-Tax) $ -- $ 98.2 $ 98.2
Regulatory Liability $ 30.0 $ -- $ 30.0
(1) Includes $34.2 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.
(2) Interest rate swaps are primarily treated as fair value hedges. Changes in
derivative values of the fair value hedges are offset by changes in the
hedged debts' premium or discount (see Interest Rate Swap Agreements
below).
(3) Excludes $9.3 million of derivative contract fair value decrease, as of
December 31, 2002, representing our 50% share of Great Lakes Energy
Partners, LLC.
(4) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
Derivatives included on the Consolidated Balance Sheet as of December 31, 2002:
NON-HEDGE HEDGE TOTAL
--------- --------- ---------
(IN MILLIONS)
CURRENT-
Other Assets $ 31.2 $ 14.9 $ 46.1
Other Liabilities (16.2) (8.8) (25.0)
NON-CURRENT-
Other Deferred Charges 39.6 39.4 79.0
Other Deferred Credits (0.8) (0.9) (1.7)
--------- --------- ---------
NET ASSETS $ 53.8 $ 44.6 $ 98.4
========= ========= =========
The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, we rely on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. We use these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of derivative contracts by year
are summarized in the following table:
20
SOURCE OF INFORMATION
- FAIR VALUE BY CONTRACT YEAR 2003 2004 2005 2006 THEREAFTER TOTAL
- ------------------------------- ------ ------ ------ ------ ---------- -----
(IN MILLIONS)
Prices actively quoted(1) $ 16.0 $ 1.5 $ -- $ -- $ -- $17.5
Other external sources(2) 22.2 2.1 (0.9) -- -- 23.4
Prices based on models -- -- -- 5.5 31.5 37.0
------ ------ ------ ------ ---------- -----
TOTAL(3) $ 38.2 $ 3.6 $ (0.9) $ 5.5 $ 31.5 $77.9
====== ====== ====== ====== ========== =====
(1) Exchange traded.
(2) Broker quote sheets.
(3) Includes $34.2 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
We perform sensitivity analyses to estimate our exposure to the
market risk of our commodity positions. 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, 2002. We estimate that if
energy commodity prices experienced an adverse 10% change, net income for the
next twelve months would decrease by approximately $3.7 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 below.
We are subject to the inherent interest rate risks related to
refinancing maturing debt by issuing new debt securities. As discussed in Note 4
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 had been
recognized by making corresponding changes to the decommissioning liability, as
described in Note 2 to the consolidated financial statements. While fluctuations
in the fair value of our Ohio EUOCs' trust balances will eventually affect
earnings (affecting OCI initially) based on the guidance provided by SFAS 115,
our non-Ohio EUOC have the opportunity to recover from customers the difference
between the investments held in trust and their decommissioning obligations.
Thus, in absence of disallowed costs, there should be no earnings effect from
fluctuations in their decommissioning trust balances. As of December 31, 2002,
decommissioning trust balances totaled $1.050 billion, with $698 million held by
our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002,
trust balances included 51% of equity and 49% of debt instruments.
COMPARISON OF CARRYING VALUE TO FAIR VALUE
- ------------------------------------------
THERE- FAIR
YEAR OF MATURITY 2003 2004 2005 2006 2007 AFTER TOTAL VALUE
- ---------------- ------ ------ ------ ------ ------ ------- ------- -------
(DOLLARS IN MILLIONS)
Assets
Investments other than Cash and Cash
Equivalents-Fixed Income $ 115 $ 327 $ 72 $ 90 $ 85 $ 1,843 $ 2,532 $ 2,638
Average interest rate 7.5% 7.8% 8.1% 8.1% 8.2% 6.3% 6.8%
Liabilities
Long-term Debt:
Fixed rate $ 964 $ 939 $ 867 $1,401 $ 252 $ 6,386 $10,809 $11,119
Average interest rate 7.7% 7.2% 8.1% 5.7% 6.7% 7.0% 7.0%
Variable rate $ 109 $ 399 $ 5 $ 1 $ 1,142 $ 1,656 $ 1,642
Average interest rate 5.4% 2.6% 6.7% 6.1% 2.7% 2.9%
Short-term Borrowings $1,093 $ 1,093 $ 1,093
Average interest rate 2.4% 2.4%
------ ------ ------ ------ ------ ------- ------- -------
Preferred Stock $ 2 $ 2 $ 2 $ 2 $ 12 $ 425 $ 445 $ 454
Average dividend rate 7.5% 7.5% 7.5% 7.5% 7.6% 8.1% 8.1%
------ ------ ------ ------ ------ ------- ------- -------
Interest Rate Swap Agreements
During 2002, FirstEnergy entered into fixed-to-floating interest
rate swap agreements, to increase the variable-rate component of its debt
portfolio from 16% to approximately 20% at year end. These derivatives are
treated as fair value hedges of fixed-rate, long-term debt issues - protecting
against the risk of changes in the fair value of fixed-rate debt instruments due
to lower interest rates. Swap maturities, call options and interest payment
dates match those of the underlying obligations. During the fourth quarter of
2002, in a period of steadily declining market interest rates, we unwound swaps
with a total notional amount of $400 million that we had entered into during the
second and third quarters of 2002. Under fair-value accounting, the swaps' fair
value ($19.9 million asset) was added to the carrying value
21
of the hedged debt and will be amortized to maturity. Offsets to interest
expense recorded in 2002 due to the difference between fixed and variable debt
rates totaled $17.4 million. As of December 31, 2002, the debt underlying
FirstEnergy's outstanding interest rate swaps had a weighted average fixed
interest rate of 7.76%, which the swaps have effectively converted to a current
weighted average variable interest rate of 3.04%. GPU Power (through a
subsidiary) used dollar-denominated interest rate swap agreements in 2002. In
2001, Penelec, GPU Power (through a subsidiary) and GPU Electric, Inc. (through
GPU Power UK) used interest rate swaps denominated in dollars and sterling. All
of the agreements of the former GPU companies convert variable-rate debt to
fixed-rate debt to manage the risk of increases in variable interest rates. GPU
Power's swaps had a weighted average fixed interest rate of 6.68% in 2002 and
6.99% in 2001. The following summarizes the principal characteristics of the
swap agreements:
INTEREST RATE SWAPS
DECEMBER 31, 2002 DECEMBER 31, 2001
---------------------------- -----------------------------
NOTIONAL MATURITY FAIR NOTIONAL MATURITY FAIR
DENOMINATION AMOUNT DATE VALUE AMOUNT DATE VALUE
- ------------ -------- -------- ----- -------- -------- -----
(DOLLARS/STERLING IN MILLIONS)
Fixed to Floating Rate
Dollar 444 2023 15.5
150 2025 5.9
Floating to Fixed Rate
Dollar 16 2005 (0.9) 50 2002 (1.8)
26 2005 (1.1)
Sterling 125 2003 (2.3)
-------- -------- ----- -------- -------- -----
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $532 million and $568
million as of December 31, 2002 and 2001, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges, would result in a $53 million
reduction in fair value as of December 31, 2002 (see Note 2J - Supplemental Cash
Flows Information).
Foreign Currency Risk
We are exposed to foreign currency risk from investments in
international business operations acquired through the merger with GPU. While
such risks are likely to diminish over time as we sell our international
operations, we expect such risks to continue in the near term. In 2002, we
experienced net foreign currency translation losses in connection with our
Argentina operations (see Note 3 - Divestitures). A hypothetical 20% adverse
change in our foreign currency positions in the near term would not have had a
material effect on our consolidated financial position, cash flows or earnings
as of December 31, 2002.
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 believe that
our strategy has received some measure of validation by the major industry
events of 2002 and we continue to build toward a strong regional presence. 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 Public Utilities Commission of Ohio (PUCO) - one
which provided a clear separation between regulated and competitive operations.
Our business is separated into three distinct units - a competitive services
segment, a regulated services segment and a corporate support segment. 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 non-nuclear 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 PLR obligations, as well as grandfathered wholesale contracts.
22
Optimizing the Use of Assets
Upon completion of its merger with GPU, FirstEnergy accepted an
October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase
Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc,
for $2.1 billion (including the assumption of $1.7 billion of debt). The
transaction closed on May 8, 2002 and reflected the March 2002 modification of
Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest
in Avon for approximately $1.9 billion (including the assumption of $1.7 billion
of debt). Proceeds to FirstEnergy included $155 million in cash and a note
receivable for approximately $87 million (representing the present value of $19
million per year to be received over six years beginning in 2003) from Aquila
for its 79.9 percent interest. FirstEnergy and Aquila together own all of the
outstanding shares of Avon through a jointly owned subsidiary, with each company
having an ownership voting interest. Originally, in accordance with applicable
accounting guidance, the earnings of those foreign operations were not
recognized in current earnings from the date of the GPU acquisition. However, as
a result of the decision to retain an ownership interest in Avon in the quarter
ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not
Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold"
required FirstEnergy to reallocate the purchase price of GPU based on amounts as
of the purchase date as if Avon had never been held for sale, including reversal
of the effects of having applied EITF Issue No. 87-11, to the transaction. The
effect of reallocating the purchase price and reversal of the effects of EITF
Issue No. 87-11, including the allocation of capitalized interest, has been
reflected in the Consolidated Statement of Income for the six months ended June
30, 2002 by reclassifying certain revenue and expense amounts related to
activity during the quarter ended March 31, 2002 to their respective income
statement classifications for the six-month 2002 period. See Note 1 for the
effects of the change in classification. In the fourth quarter of 2002,
FirstEnergy recorded a $50 million charge to reduce the carrying value of its
remaining 20.1 percent interest.
On May 22, 2003, FirstEnergy announced it reached an agreement to
sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that
agreement also includes Aquila's 79.9 percent interest. Under terms of the
agreement, Scottish and Southern will pay FirstEnergy and Aquila an aggregate
$70 million (FirstEnergy's share would be approximately $14 million). Midland's
debt will remain with that company. FirstEnergy also recognized in the second
quarter of 2003 an impairment of $12.6 million ($8.2 million net of tax) related
to the carrying value of the note FirstEnergy had with Aquila from the initial
sale of a 79.9 percent interest in Avon that occurred in May 2002. After
receiving the first annual installment payment of $19 million in May 2003,
FirstEnergy sold the remaining balance of its note receivable in a secondary
market and received $63.2 million in proceeds on July 28, 2003.
On August 8, 2002, we notified NRG that we were canceling our
agreement with it for its purchase of four fossil plants because NRG had stated
that it could not complete the sale transaction under the original terms of the
agreement. Based on subsequent bids received, we concluded that retaining the
plants to serve our customers was in the best interest of our customers and our
shareholders. Following our decision to retain the four plants, we performed a
comprehensive fossil operations review and subsequently decided to close the
Ashtabula C-Plant (three 44 megawatt (MW), coal-fired boilers). This action is
part of our strategy to provide competitively priced energy - replacing
less-efficient peaking generation in our portfolio of generation resources, with
the development of new, higher-efficiency peaking plants. While deteriorating
economic conditions in Argentina delayed our sale of Emdersa, we continue to
pursue the sale of assets that do not support our strategy in order to increase
our financial flexibility by reducing debt and preferred stock.
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in our
EUOC's respective state regulatory plans. However, despite these similarities,
the specific approach taken by each state and for each of our EUOCs varies.
Those provisions include:
- allowing the EUOC's electric customers to select their
generation suppliers;
- establishing PLR obligations to non-shopping customers in the
EUOC's service areas;
- allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
- itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
- deregulating the EUOC's electric generation businesses; and
- continuing regulation of the EUOC's transmission and
distribution systems.
23
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. 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 2002
- ------- ----
(IN MILLIONS)
OE $1,848.7
CEI 1,191.8
TE 578.2
Penn 156.9
JCP&L 3,199.0
Met-Ed 1,179.1
Penelec 599.7
- -------------------------------------
Total $8,753.4
=====================================
Ohio
FirstEnergy's transition plan (which we filed on behalf of the Ohio
Companies) included approval for recovery of transition costs, including
regulatory assets, as 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 approved plan also
granted preferred access over our subsidiaries to nonaffiliated marketers,
brokers and aggregators to 1,120 MW of generation capacity through 2005 at
established prices for sales to the Ohio Companies' retail customers. 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. In February 2003, the Ohio
Companies were authorized increases in revenues aggregating approximately $50
million (OE - $41 million, CEI - $4 million and TE - $5 million) to recover
their higher tax costs resulting from the Ohio deregulation legislation.
Our Ohio customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
respective transition cost recovery period. If the customer shopping goals
established in the agreement had not been achieved by the end of 2005, the
transition cost recovery periods could have been 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). That goal was achieved in 2002. Accordingly, FirstEnergy
does not believe that there will be any regulatory action reducing the
recoverable transition costs.
New Jersey
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L submitted two rate
filings with the NJBPU in August 2002. The first filing requested increases in
base electric rates of approximately $98 million annually. The second filing was
a request to recover deferred costs that exceeded amounts being recovered under
the current MTC and SBC rates; one proposed method of recovery of these costs is
the securitization of the deferred balance. This securitization methodology is
similar to the Oyster Creek securitization. On July 25, 2003, the NJBPU
announced its JCP&L base electric rate proceeding decision which reduces JCP&L's
annual revenues by approximately $62 million effective August 1, 2003. The NJBPU
decision also provided for an interim return on equity of 9.5 percent on JCP&L's
rate base for the next 6 to 12 months. During that period, JCP&L will initiate
another proceeding to request recovery of additional costs incurred to enhance
system reliability. In that proceeding, the NJBPU could increase the return on
equity to 9.75 percent or decrease it to 9.25 percent, depending on its
assessment of the reliability of JCP&L's service. Any reduction would be
retroactive to August 1, 2003. The revenue decrease in the decision consists of
a $223 million decrease in the electricity delivery charge, a $111 million
increase due to the August 1, 2003 expiration of annual customer credits
previously mandated by the New Jersey transition legislation, a $49 million
increase in the MTC tariff component, and a net $1 million increase in the SBC
charge. The MTC would allow for the recovery of $465 million in deferred energy
costs over the next ten years on an interim basis, thus disallowing $152.5
million. JCP&L also announced on July 25, 2003 that it is reviewing the NJBPU
decision and will decide on its appropriate course of action, which could
include filing an appeal for reconsideration with the NJBPU and possibly an
appeal to the Appellate Division of the Superior Court of New Jersey.
Pennsylvania
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to FES through a wholesale power sale which expires in December
2003 and may be extended for each successive calendar year. Under the terms of
the wholesale agreement, FES assumed the supply obligation and the supply profit
and loss risk, for the portion of power supply requirements not self-supplied by
Met-Ed and Penelec under their NUG contracts and other
24
existing power contracts with nonaffiliated third party suppliers. This
arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power
prices by providing power at or below the shopping credit for their uncommitted
PLR energy costs during the term of the agreement to FES. FES has hedged most of
Met-Ed's and Penelec's unfilled on-peak PLR obligation through 2004 and a
portion of 2005. Met-Ed and Penelec will continue to defer those cost
differences between NUG contract rates and the rates reflected in their capped
generation rates.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the Commonwealth Court's decision which effectively affirmed the
PPUC's order approving the merger between FirstEnergy and GPU, let stand the
Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and
remanded the merger savings issue back to the PPUC. Because FirstEnergy had
already reserved for the deferred energy costs and FES has largely hedged the
anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005,
FirstEnergy, Met-Ed and Penelec believe that the disallowance of competitive
transition charge recovery of PLR costs above Met-Ed's and Penelec's capped
generation rates will not have a future adverse financial impact during that
period.
On April 2, 2003, the PPUC remanded the merger savings issue to the
Office of Administrative Law for hearings and directed Met-Ed and Penelec to
file a position paper on the effect of the Commonwealth Court's order on the
Settlement Stipulation by May 2, 2003 and for the other parties to file their
responses to the Met-Ed and Penelec position paper by June 2, 2003. In summary,
the Met-Ed and Penelec position paper essentially stated the following:
- Because no stay of the PPUC's June 2001 order approving the
Settlement Stipulation was issued or sought, the Stipulation
remained in effect until the Pennsylvania Supreme Court denied all
appeal applications in January 2003,
- As of January 16, 2003, the Supreme Court's Order became final and
the portions of the PPUC's June 2001 Order that were inconsistent
with the Supreme Court's findings were reversed,
- The Supreme Court's finding effectively amended the Stipulation to
remove the PLR cost recovery and deferral provisions and reinstated
the GENCO Code of Conduct as a merger condition, and
- All other provisions included in the Stipulation unrelated to these
three issues remain in effect.
The other parties' responses included significant disagreement with
the position paper and disagreement among the other parties themselves,
including the Stipulation's original signatory parties. Some parties believe
that no portion of the Stipulation has survived the Commonwealth Court's Order.
Because of these disagreements, Met-Ed and Penelec filed a letter on June 11,
2003 with the Administrative Law Judge assigned to the remanded case voiding the
Stipulation in its entirety pursuant to the termination provisions. They believe
this will significantly simplify the issues in the pending action by reinstating
Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC.
In addition, they have agreed to voluntarily continue certain Stipulation
provisions including funding for energy and demand side response programs and to
cap distribution rates at current levels through 2007. This voluntary
distribution rate cap is contingent upon a finding that Met-Ed and Penelec have
satisfied the "public interest" test applicable to mergers and that any rate
impacts of merger savings will be dealt with in a subsequent rate case. Based
upon this letter, Met-Ed and Penelec believe that the remaining issues before
the Administrative Law Judge are the appropriate treatment of merger savings
issues and whether their accounting and related tariff modifications are
consistent with the Court Order.
FERC Regulatory Matters
On December 19, 2002, the Federal Energy Regulatory Commission
(FERC) granted unconditional Regional Transmission Organization status to PJM
Interconnection, LLC which includes JCP&L, Met-Ed and Penelec as transmission
owners. Also, on December 19, 2002, the FERC conditionally accepted
GridAmerica's filing to become an independent transmission company within
Midwest Independent System Operator, Inc. (MISO). GridAmerica will operate
ATSI's transmission facilities. GridAmercia expects to begin operations in the
second quarter of 2003 subject to approval of certain compliance filings with
the FERC. Compliance filings were made by the GridAmerica companies (including
ATSI) on January 31 and February 19, 2003.
Supply Plan
We are obligated to provide generation service for an estimated 2003
peak demand of 18,450 MW. These obligations arise from customers who have
elected to continue to receive generation service from the EUOCs under regulated
retail rate tariffs and from customers who have selected FES as their alternate
generation provider. Geographically, approximately 11,000 MW of the obligations
are in the East Central Area Reliability Agreement market and 7,450 MW are in
the PJM ISO market area. These obligations include approximately 1,700 MW of
load that FES obtained in New Jersey's BGS auction. Additionally, if alternative
suppliers fail to deliver power to their customers located in the EUOCs' service
areas, we could be required to serve an additional 1,400 MW as PLR. In the event
we must
25
procure replacement power for an alternative supplier, the cost of that power
would be recovered under the applicable state regulatory rules.
To meet their obligations, our subsidiaries have 13,101 MW of
installed generating capacity, 1,540 MW of long-term power purchase contracts
(exceeding one year), 2,800 MW under short-term purchase contracts and
approximately 800 MW of interruptible and controllable load contracts. Any
additional power requirements will be satisfied through spot market purchases.
All utilities in New Jersey are required to participate in an annual
auction through which the entire obligation for all of their BGS requirements
are auctioned to alternate suppliers. Through this auction process, the 286 MW
of JCP&L's installed capacity and approximately 800 MW of long-term purchases
from NUGs are made available to the winning bidders. FES participates in this
annual auction as an alternate supplier and currently has an obligation to
provide 1,700 MW of power for summer peak demand through July 31, 2003.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated
a formal inspection process at the Davis-Besse nuclear plant. This action was
taken in response to corrosion found by FENOC in the reactor vessel head near
the nozzle penetration hole during a refueling outage in the first quarter of
2002. The purpose of the formal inspection process is to establish criteria for
NRC oversight of the licensee's performance and to provide a record of the major
regulatory and licensee actions taken, and technical issues resolved, leading to
the NRC's approval of restart of the plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the fall of 2003. The NRC must authorize restart of the plant
following its formal inspection process before the unit can be returned to
service. While the additional maintenance work has delayed FirstEnergy's plans
to reduce post-merger debt levels FirstEnergy believes such investments in the
unit's future safety, reliability and performance to be essential. Significant
delays in Davis-Besse's return to service, which depends on the successful
resolution of the management and technical issues as well as NRC approval, could
trigger an evaluation for impairment of the nuclear plant (see Significant
Accounting Policies below).
The actual costs (capital and expense) associated with the extended Davis-Besse
outage in 2002 and estimated costs in 2003 are:
COSTS OF DAVIS-BESSE EXTENDED OUTAGE
-------------------------------------------------------------------------------------
(IN MILLIONS)
2002 - ACTUAL
-------------
Capital Expenditures:
Reactor head and restart $ 63.3
Incremental Expenses (pre-tax):
Maintenance 115.0
Fuel and purchased power 119.5
-----
Total $234.5
======
2003 - ESTIMATED
----------------
Primarily operating expenses (pre-tax):
Maintenance (including acceleration of programs) $50
Replacement power per month $12-18
-----------------------------------------------------------------------------------
We have fully hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage.
Environmental Matters
We believe we are in compliance with the current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA)
26
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 7D -
Environmental Matters). We continue to evaluate our compliance plans and other
compliance options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. 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 civil
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. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant
between 1984 and 1998 required pre-construction permits under the Clean Air Act.
The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning March 15, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, may have a material adverse impact on the
Company's financial condition and results or operations. Management is unable to
predict the ultimate outcome of this matter.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The 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; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, 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. 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 the SBC. The Companies have total accrued liabilities aggregating
approximately $54.3 million as of December 31, 2002.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on our earnings and
competitive position. These environmental regulations affect our earnings and
competitive position to the extent we compete with companies that are not
subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations. We
believe we are in material compliance with existing regulations, but are unable
to predict how and when applicable environmental regulations may change and
what, if any, the effects of any such change would be.
Legal Matters
Various lawsuits, claims and proceedings related to our 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
Nuclear Plant (TMI-2). As a result of the 1979 TMI-2 accident, claims for
alleged personal injury against JCP&L, Met-Ed, Penelec and GPU had been filed in
the U.S. District Court for the Middle District of Pennsylvania. In 1996, the
District Court granted a motion for summary
27
judgment filed by the GPU companies and dismissed the ten initial "test cases"
which had been selected for a test case trial. On January 15, 2002, the District
Court granted our motion for summary judgment on the remaining 2,100 pending
claims. On February 14, 2002, the plaintiffs filed a notice of appeal of this
decision (see Note 7E - Other Legal Proceedings). In December 2002, the Court of
Appeals for the Third Circuit refused to hear the appeal which effectively ended
further legal action for those claims.
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. 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.
It is FirstEnergy's understanding that, as of August 18, 2003, five
individual described herein shareholder-plaintiffs have filed separate
complaints against FirstEnergy Corp. alleging various securities law violations
in connection with the restatement of earnings described herein. Most of these
complaints have not yet been officially served on the Company. Moreover,
FirstEnergy is still reviewing the suits that have been served in preparation
for a responsive pleading. FirstEnergy is however, aware that in each case, the
plaintiffs are seeking certification from the court to represent a class of
similarly situated shareholders.
Power Outage
On August 14, 2003, eight states and southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. The cause of the outage has not been
determined. Having restored service to its customers, FirstEnergy is now in the
process of accumulating data and evaluating the status of its electrical system
prior to and during the outage event and would expect that the same effort Is
under way at utilities and regional transmission operators across the region.
As of August 18, 2003, the following facts about FirstEnergy's
system were known. Early in the afternoon of August 14, hours before the event,
Unit 5 of the Eastlake Plant in Eastlake, Ohio tripped off. Later in the
afternoon, three FirstEnergy transmission lines and one owned by American
Electric Power and FirstEnergy tripped out of service. The Midwest Independent
System Operator (MISO), which oversees the regional transmission grid, indicated
that there were a number of other transmission line trips in the region outside
of FirstEnergy's system. FirstEnergy customers experienced no service
interruptions resulting from these conditions. Indications to FirstEnergy were
that the Company's system was stable. Therefore, no isolation of FirstEnergy's
system was called for. In addition, FirstEnergy determined that its computerized
system for monitoring and controlling its transmission and generation system was
operating, but the alarm screen function was not. However, MISO's monitoring
system was operating properly. FirstEnergy believes that extensive data needs to
be gathered and analyzed in order to determine with any degree of certainty the
circumstances that led to the outage. This is a very complex situation, far
broader than the power line outages FirstEnergy experienced on its system. From
the preliminary data that has been gathered, FirstEnergy believes that the
transmission grid in the Eastern Interconnection, not just within FirstEnergy's
system, was experiencing unusual electrical conditions at various times prior to
the event. These included unusual voltage and frequency fluctuations and load
swings on the grid. FirstEnergy is committed to working with the North American
Electric Reliability Council and others involved to determine exactly what
events in the entire affected region led to the outage. There is no timetable as
to when this entire process will be completed. It is, however, expected to last
several weeks, at a minimum.
IMPLEMENTATION OF RECENT ACCOUNTING STANDARD
In June 2002, the Emerging Issues Task Force (EITF) reached a
partial consensus on Issue No. 02-03, "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities." Based on the EITF's partial consensus
position, for periods after July 15, 2002, mark-to-market revenues and expenses
and their related kilowatt-hour (KWH) sales and purchases on energy trading
contracts must be shown on a net basis in the Consolidated Statements of Income.
We have previously reported such contracts as gross revenues and purchased power
costs. Comparative quarterly disclosures and the Consolidated Statements of
Income for revenues and expenses have been reclassified for 2002 only to conform
with the revised
28
presentation (see Note 11 - Summary of Quarterly Financial Data). In addition,
the related KWH sales and purchases statistics described above under Results of
Operations were reclassified (7.2 billion KWH in 2002 and 3.7 KWH billion in
2001). The following table displays the impact of changing to a net presentation
for our energy trading operations.
2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES
-----------------------------------------------------------------------------------
RESTATED
-----------------------------------------------------------------------
(SEE NOTES 2(L) AND 2(M))
---------------------------------------------------------------------------------
(IN MILLIONS)
Total before adjustment $12,515 $10,378
Adjustment (268) (268)
-------------------------------------------------------------------------------------
Total as reported $12,247 $10,110
====================================================================================
SIGNIFICANT ACCOUNTING POLICIES
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
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 post-retirement benefit assets and liabilities. The purchase
price allocations for the GPU acquisition were finalized in the fourth quarter
of 2002 (see Note 12).
Regulatory Accounting
Our regulated services segment is subject to regulation that sets
the prices (rates) it is permitted to charge its customers based on 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 - $8.8
billion as of December 31, 2002. We regularly review these assets to assess
their ultimate recoverability within the approved regulatory guidelines.
Impairment risk associated with these assets relates to potentially adverse
legislative, judicial or regulatory actions in the future.
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 are
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 their
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 commodity contracts, as
well as interest rate and currency swaps, which increase the impact of
derivative accounting judgments.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for KWH that have been delivered but not yet billed through the end of
the accounting period. The determination of unbilled revenues requires
management to make various estimates including:
29
- Net energy generated or purchased for retail load
- Losses of energy over transmission and distribution lines
- Mix of KWH usage by residential, commercial and industrial
customers
- KWH usage of customers receiving electricity from alternative
suppliers
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions we make to the plans, and earnings on plan assets. Such factors
may be further affected by business combinations (such as our merger with GPU,
Inc. in November 2001), which impacts employee demographics, plan experience and
other factors. Pension and OPEB costs may also be affected by changes to key
assumptions, including anticipated rates of return on plan assets, the discount
rates and health care trend rates used in determining the projected benefit
obligations and pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently
available rates of return on high-quality fixed income investments expected to
be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, we reduced the assumed
discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75%
used in 2000.
Our assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by our pension trusts. The market values of our pension assets have been
affected by sharp declines in the equity markets since mid-2000. In 2002, 2001
and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our
pension costs in 2002 were computed assuming a 10.25% rate of return on plan
assets. As of December 31, 2002 the assumed return on plan assets was reduced to
9.00% based upon our projection of future returns and pension trust investment
allocation of approximately 60% large cap equities, 10% small cap equities and
30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, we will not be required to fund our pension plans in 2003. While OPEB
plan assets have also been affected by sharp declines in the equity market, the
impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates. The effect on our SFAS 87 and 106
costs and liabilities from changes in key assumptions are as follows:
INCREASE IN COSTS FROM ADVERSE CHANGES IN KEY ASSUMPTIONS
-----------------------------------------------------------------------------------------------
ASSUMPTION ADVERSE CHANGE PENSION OPEB TOTAL
-----------------------------------------------------------------------------------------------
(IN MILLIONS)
Discount rate Decrease by 0.25% $10.3 $ 7.4 $17.7
Long-term return on assets Decrease by 0.25% $ 6.9 $ 1.2 $ 8.1
Health care trend rate Increase by 1% na $20.7 $20.7
INCREASE IN MINIMUM LIABILITY
Discount rate Decrease by 0.25% $99.4 na $99.4
------------------------------------------------------------------------------------------------
30
As a result of the reduced market value of our pension plan assets,
we were required to recognize an additional minimum liability as prescribed by
SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement
Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of
$286.9 million and established a minimum liability of $548.6 million, recording
an intangible asset of $78.5 million and reducing OCI by $444.2 million
(recording a related deferred tax benefit of $312.8 million). The charge to OCI
will reverse in future periods to the extent the fair value of trust assets
exceed the accumulated benefit obligation. The amount of pension liability
recorded as of December 31, 2002 increased due to the lower discount rate
assumed and reduced market value of plan assets as of December 31, 2002. Our
non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is
expected to increase by $125 million and $45 million, respectively - a total of
$170 million in 2003 as compared to 2002.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset, is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, we recognize a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
Goodwill
The regulators in the jurisdictions that the Companies operate in do
not provide recovery at goodwill. As a result, no amortization has been recorded
subsequent to the adoption of SFAS 142. In a business combination, the excess of
the purchase price over the estimated fair values of the assets acquired and
liabilities assumed is recognized as goodwill. Based on the guidance provided by
SFAS 142, we evaluate our goodwill for impairment at least annually and would
make such an evaluation more frequently if indicators of impairment should
arise. In accordance with the accounting standard, if the fair value of a
reporting unit is less than its carrying value including goodwill, an impairment
for goodwill must be recognized in the financial statements. If impairment were
to occur we would recognize a loss - calculated as the difference between the
implied fair value of a reporting unit's goodwill and the carrying value of the
goodwill. Our annual review was completed in the third quarter of 2002. The
results of that review indicated no impairment of goodwill -- fair value was
higher than carrying value for each of our reporting units. The forecasts used
in our evaluations of goodwill reflect operations consistent with our general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on our future evaluations of goodwill. As of December 31,
2002, we had $6.3 billion of goodwill that primarily relates to our regulated
services segment.
31
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
SFAS 143, "Accounting for Asset Retirement Obligations"
In June 2001, the FASB issued SFAS 143. The new statement provides
accounting standards for retirement obligations associated with tangible
long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Over time the capitalized costs are depreciated and the present value of the
asset retirement liability increases, resulting in a period expense. However,
rate-regulated entities may recognize regulatory assets or liabilities if the
criteria for such treatment are met. Upon retirement, a gain or loss would be
recorded if the cost to settle the retirement obligation differs from the
carrying amount.
We have identified applicable legal obligations as defined under the
new standard, principally for nuclear power plant decommissioning. Upon adoption
of SFAS 143 in January 2003, asset retirement costs of $602 million were
recorded as part of the carrying amount of the related long-lived asset, offset
by accumulated depreciation of $415 million. Due to the increased carrying
amount, the related long-lived assets were tested for impairment in accordance
with SFAS 144. No impairment was indicated. The asset retirement liability at
the date of adoption was $1.109 billion. As of December 31, 2002, FirstEnergy
had recorded decommissioning liabilities of $1.232 billion, including unrealized
gains on decommissioning trust funds of $12 million. The change in the estimated
liabilities resulted from changes in methodology and various assumptions,
including changes in the projected dates for decommissioning.
Management expects that substantially all nuclear decommissioning
costs for Met-Ed, Penelec, JCP&L and Penn will be recoverable through their
regulated rates. Therefore, we recognized a regulatory liability of $185 million
upon adoption of SFAS 143 for the transition amounts related to establishing the
asset retirement obligations for nuclear decommissioning. The remaining
cumulative effect adjustment to recognize the undepreciated asset retirement
cost and the asset retirement liability offset by the reversal of the previously
recorded decommissioning liabilities was a $175 million increase to income ($102
million net of tax).
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities"
This statement, which was issued by the FASB in July 2002, requires
the recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (Including Certain Costs Incurred in a
Restructuring)." This new standard was effective for exit and disposal
activities initiated after December 31, 2002. Since it is applied prospectively,
there will be no impact upon adoption. However, SFAS 146 could change the timing
and amount of costs recognized in connection with future exit or disposal
activities.
SFAS 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure"
SFAS 148 provides alternative approaches for voluntarily
transitioning to the fair value method of accounting for stock-based
compensation as described by SFAS 123 "Accounting for Stock-Based Compensation."
Under current GAAP, we do not intend to adopt fair value accounting. It also
amends SFAS 123 disclosure requirements for those companies applying APB 25,
"Accounting for Stock Issued to Employees" and FASB Interpretation 44,
"Accounting for Transactions involving Stock Compensation - an interpretation of
APB Opinion No. 44." The amendment requires prominent display of differences
between the SFAS 123 fair-value approach and the intrinsic-value approach
described by APB 25 in a prescribed format. SFAS 148 also amends APB 28,
"Interim Financial Reporting," to require that these disclosures be made on an
interim basis. The new disclosure requirements are effective for 2002 year-end
reporting (see Note 2B - Earnings Per Share) and for quarterly reporting
beginning in 2003. Application of the alternative transition approaches is
effective in 2003.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness
of Others - an interpretation of FASB Statements No. 5, 57, and 107 and
rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation
identifies minimum guarantee disclosures required for annual periods ending
after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies
that providers of guarantees must record the fair value of those guarantees at
their inception. This accounting guidance is applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. We do not believe that
implementation of FIN 45 will be material but we will continue to evaluate
anticipated guarantees.
32
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (FirstEnergy's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements, the sale of preferred securities and debt
secured by bondable property, which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46.
FirstEnergy currently consolidates the majority of these entities
and believes it will continue to consolidate following the adoption of FIN 46.
In addition to the entities FirstEnergy is currently consolidating FirstEnergy
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $11.6 million.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the
standard, certain financial instruments that embody obligations for the issuer
are required to be classified as liabilities. SFAS 150 is effective for
financial instruments entered into or modified after May 31, 2003 and is
effective at the beginning of the first interim period beginning after June 15,
2003 (FirstEnergy's third quarter of 2003) for all other financial instruments.
FirstEnergy did not enter into or modify any financial instruments
within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150,
effective July 1, 2003, FirstEnergy expects to classify as debt the preferred
stock of consolidated subsidiaries subject to mandatory redemptions with a
carrying value of approximately $19 million as of June 30, 2003. Subsidiary
preferred dividends on FirstEnergy's Consolidated Statements of Income are
currently included in net interest charges. Therefore, the application of SFAS
150 will not require the reclassification of such preferred dividends to net
interest charges.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph
10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003 which would correspond to
FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue
C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify
for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides
guidance regarding when the presence in a contract of a general index, such as
the Consumer Price Index, would prevent that contract from qualifying for the
normal purchases and normal sales (NPNS) exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts.
DIG Issue C20 is to be applied prospectively to all existing contracts as of
its effective date and for all future transactions. If it is determined under
DIG Issue C20 guidance that the NPNS exception was claimed for an existing
contract that was not eligible for this exception, the contract will be
recorded at fair value, with a corresponding adjustment of net income as the
cumulative effect of a change in accounting principle in the fourth quarter of
2003. FirstEnergy is currently assessing the new guidance and has not yet
determined the impact on its financial statements.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when
arrangements contain a lease. Based on the EITF consensus, an arrangement
contains a lease if (1) it identifies specific property, plant or equipment
(explicitly or implicitly), and (2) the arrangement transfers the right to the
purchaser to control the use of the property, plant or equipment. The consensus
will be applied prospectively to arrangements committed to, modified or
acquired through a business combination, beginning in the third quarter of
2003. FirstEnergy is currently assessing the new EITF consensus and has not yet
determined the impact on its financial position or results of operations
following adoption.
33
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
RESTATED
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Electric utilities ......................................... $ 9,165,805 $ 5,729,036 $ 5,421,668
Unregulated businesses ..................................... 3,064,721 2,270,326 1,607,293
------------ ----------- -----------
Total revenues ......................................... 12,230,526 7,999,362 7,028,961
------------ ----------- -----------
EXPENSES:
Fuel and purchased power ................................... 3,662,910 1,421,525 1,110,845
Purchased gas .............................................. 592,116 820,031 553,548
Other operating expenses (Note 2(M)) ....................... 3,888,909 2,727,794 2,378,296
Provision for depreciation and amortization (Note 2(M)) .... 1,305,843 889,550 933,684
General taxes .............................................. 650,329 455,340 547,681
------------ ----------- -----------
Total expenses ......................................... 10,100,107 6,314,240 5,524,054
------------ ----------- -----------
INCOME BEFORE INTEREST AND INCOME TAXES ....................... 2,130,419 1,685,122 1,504,907
------------ ----------- -----------
NET INTEREST CHARGES:
Interest expense ........................................... 910,272 519,131 493,473
Capitalized interest ....................................... (24,474) (35,473) (27,059)
Subsidiaries' preferred stock dividends .................... 75,647 72,061 62,721
------------ ----------- -----------
Net interest charges ................................... 961,445 555,719 529,135
------------ ----------- -----------
INCOME TAXES .................................................. 528,694 474,457 376,802
------------ ----------- -----------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGES ............................... 640,280 654,946 598,970
------------ ----------- -----------
Discontinued operations .................................... (87,476) -- --
Cumulative effect of accounting change (net of
income tax benefit of $5,839,000) (Note 2(J)) ............ -- (8,499) --
------------ ----------- -----------
NET INCOME .................................................... $ 552,804 $ 646,447 $ 598,970
============ =========== ===========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect
of accounting change .................................... $ 2.19 $ 2.85 $ 2.69
Discontinued operations (Note 2(M)) ........................ (0.30) -- --
Cumulative effect of accounting change (Note 2(J)) ......... -- (.03) --
------------ ----------- -----------
Net income ................................................. $ 1.89 $ 2.82 $ 2.69
============ =========== ===========
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING ........... 293,194 229,512 222,444
============ =========== ===========
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect
of accounting change .................................... $ 2.18 $ 2.84 $ 2.69
Discontinued operations (Note 2(M)) ........................ (0.30) -- --
Cumulative effect of accounting change (Note 2(J)) ......... -- (.03) --
------------ ----------- -----------
Net income ................................................. $ 1.88 $ 2.81 $ 2.69
============ =========== ===========
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING ......... 294,421 230,430 222,726
============ =========== ===========
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK .................. $ 1.50 $ 1.50 $ 1.50
============ =========== ===========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
34
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2002 2001
- ---------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 2(M))
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................................ $ 196,301 $ 220,178
Receivables-
Customers (less accumulated provisions of $52,514,000 and $65,358,000,
respectively, for uncollectible accounts) ............................ 1,153,486 1,074,664
Other (less accumulated provisions of $12,851,000 and $7,947,000,
respectively, for uncollectible accounts) ............................ 469,606 473,550
Materials and supplies, at average cost-
Owned .................................................................. 253,047 256,516
Under consignment ...................................................... 174,028 141,002
Prepayments and other .................................................... 203,630 336,610
----------- -----------
2,450,098 2,502,520
----------- -----------
ASSETS PENDING SALE (NOTE 3) ................................................ -- 3,418,225
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service ............................................................... 20,372,224 19,981,749
Less--Accumulated provision for depreciation ............................. 8,552,927 8,161,022
----------- -----------
11,819,297 11,820,727
Construction work in progress ............................................ 859,016 607,702
----------- -----------
12,678,313 12,428,429
----------- -----------
INVESTMENTS:
Capital trust investments (Note 4) ....................................... 1,079,435 1,166,714
Nuclear plant decommissioning trusts ..................................... 1,049,560 1,014,234
Letter of credit collateralization (Note 4) .............................. 277,763 277,763
Pension investments (Note 2(I)) .......................................... -- 273,542
Other .................................................................... 918,874 898,311
----------- -----------
3,325,632 3,630,564
----------- -----------
DEFERRED CHARGES:
Regulatory assets ........................................................ 8,753,401 8,912,584
Goodwill ................................................................. 6,278,072 5,600,918
Other (Note 2I) .......................................................... 900,837 858,273
----------- -----------
15,932,310 15,371,775
----------- -----------
$34,386,353 $37,351,513
=========== ===========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock ..................... $ 1,702,822 $ 1,867,657
Short-term borrowings (Note 6) ........................................... 1,092,817 614,298
Accounts payable ......................................................... 906,468 704,184
Accrued taxes ............................................................ 455,121 418,555
Other .................................................................... 1,093,815 1,064,763
----------- -----------
5,251,043 4,669,457
----------- -----------
LIABILITIES RELATED TO ASSETS PENDING SALE (NOTE 3) ......................... -- 2,954,753
----------- -----------
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders' equity .............................................. 7,050,661 7,398,599
Preferred stock of consolidated subsidiaries--
Not subject to mandatory redemption .................................... 335,123 480,194
Subject to mandatory redemption ........................................ 18,521 65,406
Subsidiary-obligated mandatorily redeemable preferred securities (Note 5(F)) 409,867 529,450
Long-term debt ........................................................... 10,872,216 11,433,313
----------- -----------
18,686,388 19,906,962
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes ........................................ 2,069,682 2,684,219
Accumulated deferred investment tax credits .............................. 236,184 260,532
Nuclear plant decommissioning costs ...................................... 1,243,558 1,201,599
Power purchase contract loss liability ................................... 3,136,538 3,566,531
Retirement benefits ...................................................... 1,564,930 838,943
Other .................................................................... 2,198,030 1,268,517
----------- -----------
10,448,922 9,820,341
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7) ...................
----------- -----------
$34,386,353 $37,351,513
=========== ===========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
35
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
AS OF DECEMBER 31, 2002 2001
- ----------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 2(M))
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $0.10 par value - authorized 375,000,000 shares-
297,636,276 shares outstanding ............................. $ 29,764 $ 29,764
Other paid-in capital ........................................ 6,120,341 6,113,260
Accumulated other comprehensive loss (Note 5I) ............... (656,148) (169,003)
Retained earnings (Note 5A) .................................. 1,634,981 1,521,805
Unallocated employee stock ownership plan common stock-
3,966,269 and 5,117,375 shares, respectively (Note 5B) ..... (78,277) (97,227)
----------- -----------
Total common stockholders' equity .......................... 7,050,661 7,398,599
----------- -----------
NUMBER OF SHARES OPTIONAL
OUTSTANDING REDEMPTION PRICE
-------------------------- ---------------------
2002 2001 PER SHARE AGGREGATE
---------- ---------- --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Note 5D):
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 -- -- -- 100,000
---------- ---------- ------- -------- --------
Total Not Subject to
Mandatory Redemption ................... 609,650 4,609,650 $63,893 60,965 160,965
========== ========== ======= -------- --------
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 5E):
7.625% ................................. 142,500 150,000 103.81 $14,793 14,250 15,000
Redemption Within One Year ............... (750) (750)
---------- ---------- ------- -------- --------
Total Subject to Mandatory Redemption .. 142,500 150,000 $14,793 13,500 14,250
========== ========== ======= -------- --------
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 -- -- -- 45,071
Adjustable Series L .................... 474,000 474,000 100.00 47,400 46,404 46,404
$42.40 Series T ........................ -- 200,000 -- -- -- 96,850
---------- ---------- ------- -------- --------
974,000 1,624,000 97,900 96,404 238,325
Redemption Within One Year ............... -- (96,850)
---------- ---------- ------- -------- --------
Total Not Subject to Mandatory
Redemption ............................. 974,000 1,624,000 $97,900 96,404 141,475
========== ========== ======= -------- --------
Subject to Mandatory Redemption (Note 5E):
$ 7.35 Series C ........................ 60,000 70,000 101.00 $ 6,060 6,021 7,030
$90.00 Series S ........................ -- 17,750 -- -- -- 17,268
---------- ---------- ------- -------- --------
60,000 87,750 6,060 6,021 24,298
Redemption Within One Year ............... (1,000) (18,010)
---------- ---------- ------- -------- --------
Total Subject to Mandatory Redemption .. 60,000 87,750 $ 6,060 5,021 6,288
========== ========== ======= -------- --------
36
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
AS OF DECEMBER 31, 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------
RESTATED
(SEE NOTE 2(M))
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
NUMBER OF SHARES OPTIONAL
OUTSTANDING REDEMPTION PRICE
------------------------- ----------------------
2002 2001 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 -- -- -- 10,000
$ 7.76 .............................. -- 150,000 -- -- -- 15,000
$ 7.80 .............................. -- 150,000 -- -- -- 15,000
$10.00 .............................. -- 190,000 -- -- -- 19,000
---------- ---------- -------- -------- --------
310,000 900,000 31,990 31,000 90,000
Redemption Within One Year ............ -- (59,000)
---------- ---------- -------- -------- --------
310,000 900,000 31,990 31,000 31,000
---------- ---------- -------- -------- --------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$2.21 ............................... -- 1,000,000 -- -- -- 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
---------- ---------- -------- -------- --------
3,800,000 4,800,000 98,850 95,000 120,000
Redemption Within One Year ............ -- (25,000)
---------- ---------- -------- -------- --------
3,800,000 4,800,000 98,850 95,000 95,000
---------- ---------- -------- -------- --------
Total Not Subject to Mandatory
Redemption ........................ 4,110,000 5,700,000 $130,840 126,000 126,000
========== ========== ======== -------- --------
Jersey Central Power & Light Company
Cumulative, $100 stated value-
Authorized 15,600,000 shares
Not Subject to Mandatory Redemption:
4.00% Series ........................ 125,000 125,000 106.50 $ 13,313 12,649 12,649
========== ========== ======== -------- --------
Subject to Mandatory Redemption:
8.65% Series J ...................... -- 250,001 -- $ -- -- 26,750
7.52% Series K ...................... -- 265,000 -- -- -- 28,951
---------- ---------- -------- -------- --------
-- 515,001 -- -- 55,701
Redemption Within One Year ............ -- (10,833)
---------- ---------- -------- -------- --------
Total Subject to Mandatory Redemption -- 515,001 $ -- -- 44,868
========== ========== ======== -------- --------
SUBSIDIARY-OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST OR LIMITED PARTNERSHIP
HOLDING SOLELY SUBORDINATED DEBENTURES
OF SUBSIDIARIES (NOTE 5F):
Ohio Edison Co.
Cumulative, $25 stated value-
Authorized 4,800,000 shares
9.00% ................................. -- 4,800,000 -- $ -- -- 120,000
========== ========== ======== -------- --------
Cleveland Electric Illuminating Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
9.00% ................................. 4,000,000 4,000,000 -- $ -- 100,000 100,000
========== ========== ======== -------- --------
Jersey Central Power & Light Co.
Cumulative, $25 stated value-
Authorized 5,000,000 shares
8.56% ................................. 5,000,000 5,000,000 25.00 $125,000 125,244 125,250
========== ========== ======== -------- --------
Metropolitan Edison Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
7.35% ................................. 4,000,000 4,000,000 -- $ -- 92,409 92,200
========== ========== ======== -------- --------
Pennsylvania Electric Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
7.34% ................................. 4,000,000 4,000,000 -- $ -- 92,214 92,000
========== ========== ======== -------- --------
37
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (NOTE 5G) (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (IN THOUSANDS)
- ------------------------------------------------------------------------------------------------------------------------------
FIRST MORTGAGE BONDS SECURED NOTES
- ------------------------------------------------------------------------------------------------------------------------------
AS OF DECEMBER 31, 2002 2001 2002 2001
-------- ---------- ---------- ----------
Ohio Edison Co. -
Due 2002-2007 ................. 8.02% $230,000 $ 509,265 7.66% $ 186,549 $ 231,907
Due 2008-2012 ................. -- -- -- 7.00% 5,468 5,468
Due 2013-2017 ................. -- -- -- 5.09% 59,000 59,000
Due 2018-2022 ................. 8.75% 50,960 50,960 7.01% 60,443 60,443
Due 2023-2027 ................. 7.76% 168,500 168,500 -- -- --
Due 2028-2032 ................. -- -- -- 3.60% 249,634 249,634
Due 2033-2037 ................. -- -- -- 2.43% 71,900 71,900
-------- ---------- ---------- ----------
Total-Ohio Edison ................ 449,460 728,725 632,994 678,352
-------- ---------- ---------- ----------
Cleveland Electric
Illuminating Co. -
Due 2002-2007 ................. 8.97% 400,000 595,000 5.74% 680,175 713,205
Due 2008-2012 ................. 6.86% 125,000 125,000 7.43% 151,610 151,610
Due 2013-2017 ................. -- -- -- 7.88% 300,000 378,700
Due 2018-2022 ................. -- -- -- 6.24% 140,560 140,560
Due 2023-2027 ................. 9.00% 150,000 150,000 7.64% 218,950 218,950
Due 2028-2032 ................. -- -- -- 5.38% 5,993 5,993
Due 2033-2037 ................. -- -- -- 1.60% 30,000 --
-------- ---------- ---------- ----------
Total-Cleveland Electric ......... 675,000 870,000 1,527,288 1,609,018
-------- ---------- ---------- ----------
Toledo Edison Co. -
Due 2002-2007 ................. 7.90% 178,725 179,125 6.19% 229,700 258,700
Due 2008-2012 ................. -- -- -- -- -- --
Due 2013-2017 ................. -- -- -- -- -- --
Due 2018-2022 ................. -- -- -- 7.89% 114,000 129,000
Due 2023-2027 ................. -- -- -- 7.31% 60,800 60,800
Due 2028-2032 ................. -- -- -- 5.38% 3,751 3,751
Due 2033-2037 ................. -- -- -- 1.68% 51,100 30,900
-------- ---------- ---------- ----------
Total-Toledo Edison .............. 178,725 179,125 459,351 483,151
-------- ---------- ---------- ----------
Pennsylvania Power Co. -
Due 2002-2007 ................. 7.19% 79,370 80,344 2.99% 10,300 10,300
Due 2008-2012 ................. 9.74% 4,870 4,870 -- -- --
Due 2013-2017 ................. 9.74% 4,870 4,870 3.12% 29,525 29,525
Due 2018-2022 ................. 8.58% 29,231 29,231 3.94% 31,282 31,282
Due 2023-2027 ................. 7.63% 6,500 6,500 6.15% 12,700 27,200
Due 2028-2032 ................. -- -- -- 5.79% 23,172 23,172
-------- ---------- ---------- ----------
Total-Penn Power ................. 124,841 125,815 106,979 121,479
-------- ---------- ---------- ----------
Jersey Central Power & Light Co. -
Due 2002-2007 ................. 6.90% 442,674 541,260 5.60% 241,135 150,000
Due 2008-2012 ................. 7.13% 5,040 5,040 5.39% 52,273 --
Due 2013-2017 ................. 7.10% 12,200 12,200 6.01% 176,592 --
Due 2018-2022 ................. 8.62% 76,586 170,000 -- -- --
Due 2023-2027 ................. 7.37% 365,000 365,000 -- -- --
Due 2028-2032 ................. -- -- -- -- -- --
Due 2033-2037 ................. -- -- -- -- -- --
Due 2038-2042 ................. -- -- -- -- -- --
-------- ---------- ---------- ----------
Total-Jersey Central ............. 901,500 1,093,500 470,000 150,000
-------- ---------- ---------- ----------
Metropolitan Edison Co. -
Due 2002-2007 ................. 6.71% 202,175 262,175 5.79% 150,000 100,000
Due 2008-2012 ................. 6.00% 6,525 6,525 -- -- --
Due 2013-2017 ................. -- -- -- -- -- --
Due 2018-2022 ................. 7.86% 88,500 88,500 -- -- --
Due 2023-2027 ................. 7.55% 133,690 133,690 -- -- --
Due 2028-2032 ................. -- -- -- -- -- --
Due 2033-2037 ................. -- -- -- -- -- --
Due 2038-2042 ................. -- -- -- -- -- --
-------- ---------- ---------- ----------
Total-Metropolitan Edison ........ 430,890 490,890 150,000 100,000
-------- ---------- ---------- ----------
LONG-TERM DEBT (NOTE 5G) (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (IN THOUSANDS)
- -------------------------------------------------------------------------------------------------------------
UNSECURED NOTES TOTAL
- -------------------------------------------------------------------------------------------------------------
AS OF DECEMBER 31, 2002 2001 2002 2001
-------- -------- ----------- -----------
RESTATED
(SEE NOTE 2(M))
Ohio Edison Co. -
Due 2002-2007 ................. 4.17% $441,725 $441,725
Due 2008-2012 ................. -- -- --
Due 2013-2017 ................. -- -- --
Due 2018-2022 ................. -- -- --
Due 2023-2027 ................. -- -- --
Due 2028-2032 ................. -- -- --
Due 2033-2037 ................. -- -- --
-------- -------- ----------- -----------
Total-Ohio Edison ................ 441,725 441,725 $ 1,524,179 $ 1,848,802
-------- -------- ----------- -----------
Cleveland Electric
Illuminating Co. -
Due 2002-2007 ................. 5.58% 27,700 27,700
Due 2008-2012 ................. -- -- --
Due 2013-2017 ................. 6.00% 78,700 --
Due 2018-2022 ................. -- -- --
Due 2023-2027 ................. -- -- --
Due 2028-2032 ................. -- -- --
Due 2033-2037 ................. -- -- --
-------- -------- ----------- -----------
Total-Cleveland Electric ......... 106,400 27,700 2,308,688 2,506,718
-------- -------- ----------- -----------
Toledo Edison Co. -
Due 2002-2007 ................. 4.83% 91,100 226,130
Due 2008-2012 ................. 10.00% 760 760
Due 2013-2017 ................. -- -- --
Due 2018-2022 ................. -- -- --
Due 2023-2027 ................. -- -- --
Due 2028-2032 ................. -- -- --
Due 2033-2037 ................. -- -- --
-------- -------- ----------- -----------
Total-Toledo Edison .............. 91,860 226,890 729,936 889,166
-------- -------- ----------- -----------
Pennsylvania Power Co. -
Due 2002-2007 ................. 4.39% 19,700 5,200
Due 2008-2012 ................. -- -- --
Due 2013-2017 ................. -- -- --
Due 2018-2022 ................. -- -- --
Due 2023-2027 ................. -- -- --
Due 2028-2032 ................. -- -- --
-------- -------- ----------- -----------
Total-Penn Power ................. 19,700 5,200 251,520 252,494
-------- -------- ----------- -----------
Jersey Central Power & Light Co. -
Due 2002-2007 ................. 7.69% 93 107
Due 2008-2012 ................. 7.69% 134 134
Due 2013-2017 ................. 7.69% 193 193
Due 2018-2022 ................. 7.69% 280 280
Due 2023-2027 ................. 7.69% 406 406
Due 2028-2032 ................. 7.69% 588 588
Due 2033-2037 ................. 7.69% 851 851
Due 2038-2042 ................. 7.69% 439 439
-------- -------- ----------- -----------
Total-Jersey Central ............. 2,984 2,998 1,374,484 1,246,498
-------- -------- ----------- -----------
Metropolitan Edison Co. -
Due 2002-2007 ................. 7.69% 185 214
Due 2008-2012 ................. 7.69% 267 267
Due 2013-2017 ................. 7.69% 387 387
Due 2018-2022 ................. 7.69% 560 560
Due 2023-2027 ................. 7.69% 812 812
Due 2028-2032 ................. 7.69% 1,176 1,176
Due 2033-2037 ................. 7.69% 1,703 1,703
Due 2038-2042 ................. 7.69% 878 878
-------- -------- ----------- -----------
Total-Metropolitan Edison ........ 5,968 5,997 586,858 596,887
-------- -------- ----------- -----------
38
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
- ---------------------------------------------------------------------------------------------------------------------------
AS OF DECEMBER 31, 2002 2001 2002 2001
---------- ---------- ---------- ----------
RESTATED
(SEE NOTE 2(M))
Pennsylvania Electric Co. -
Due 2002-2007 6.13% $ 3,905 $ 4,110 -- $ -- $ --
Due 2008-2012 5.35% 24,310 24,310 -- -- --
Due 2013-2017 -- -- -- -- -- --
Due 2018-2022 5.80% 20,000 20,000 -- -- --
Due 2023-2027 6.05% 25,000 25,000 -- -- --
Due 2028-2032 -- -- -- -- -- --
Due 2033-2037 -- -- -- -- -- --
Due 2038-2042 -- -- -- -- -- --
---------- ---------- ---------- ----------
Total-Pennsylvania Electric 73,215 73,420 -- --
---------- ---------- ---------- ----------
FirstEnergy Corp. -
Due 2002-2007 -- -- -- -- -- --
Due 2008-2012 -- -- -- -- -- --
Due 2013-2017 -- -- -- -- -- --
Due 2018-2022 -- -- -- -- -- --
Due 2023-2027 -- -- -- -- -- --
Due 2028-2032 -- -- -- -- -- --
---------- ---------- ---------- ----------
Total-FirstEnergy -- -- -- --
---------- ---------- ---------- ----------
OES Fuel -- -- -- -- 81,515
AFN Finance Co. No. 1 -- -- -- -- 15,000
AFN Finance Co. No. 3 -- -- -- -- 4,000
Bay Shore Power -- -- 6.24% 143,200 145,400
MARBEL Energy Corp. -- -- -- -- --
Facilities Services Group -- -- 4.86% 13,205 15,735
FirstEnergy Generation -- -- -- -- --
FirstEnergy Properties -- -- 7.89% 9,679 9,902
Warrenton River Terminal -- -- 5.25% 634 776
GPU Capital* -- -- -- -- --
GPU Power -- -- 7.14% 174,760 239,373
---------- ---------- ---------- ----------
Total $2,833,631 $3,561,475 $3,688,090 $3,653,701
========== ========== ========== ==========
Capital lease obligations .................................................................................................
Net unamortized premium on debt* ..........................................................................................
Long-term debt due within one year*........................................................................................
Total long-term debt* .....................................................................................................
TOTAL CAPITALIZATION* .....................................................................................................
- ---------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (CONT'D) (IN THOUSANDS)
- -----------------------------------------------------------------------------------------------------------------------
UNSECURED NOTES TOTAL
- -----------------------------------------------------------------------------------------------------------------------
AS OF DECEMBER 31, 2002 2001 2002 2001
---------- ---------- -------------- --------------
Pennsylvania Electric Co. -
Due 2002-2007 5.86% $ 133,093 $ 183,107
Due 2008-2012 6.55% 135,134 135,134
Due 2013-2017 7.69% 193 193
Due 2018-2022 6.63% 125,280 125,280
Due 2023-2027 7.69% 406 406
Due 2028-2032 7.69% 588 588
Due 2033-2037 7.69% 851 851
Due 2038-2042 7.69% 439 439
---------- ---------- -------------- --------------
Total-Pennsylvania Electric 395,984 445,998 $ 469,199 $ 519,418
---------- ---------- -------------- --------------
FirstEnergy Corp. -
Due 2002-2007 5.28% 1,695,000 1,550,000
Due 2008-2012 6.45% 1,500,000 1,500,000
Due 2013-2017 -- -- --
Due 2018-2022 -- -- --
Due 2023-2027 -- -- --
Due 2028-2032 7.38% 1,500,000 1,500,000
---------- ---------- -------------- --------------
Total-FirstEnergy 4,695,000 4,550,000 4,695,000 4,550,000
---------- ---------- -------------- --------------
OES Fuel -- -- -- -- 81,515
AFN Finance Co. No. 1 -- -- -- -- 15,000
AFN Finance Co. No. 3 -- -- -- -- 4,000
Bay Shore Power -- -- -- 143,200 145,400
MARBEL Energy Corp. -- -- 569 -- 569
Facilities Services Group -- -- -- 13,205 15,735
FirstEnergy Generation 5.00% 15,000 -- 15,000 --
FirstEnergy Properties -- -- -- 9,679 9,902
Warrenton River Terminal -- -- -- 634 776
GPU Capital* 5.78% 101,467 1,629,582 101,467 1,629,582
GPU Power 11.87% 67,372 56,048 242,132 295,421
---------- ---------- -------------- --------------
Total $5,943,460 $7,392,707 12,465,181 14,607,883
========== ========== -------------- --------------
Capital lease obligations ....................................................... 15,761 19,390
Net unamortized premium on debt* ................................................ 92,346 213,834
Long-term debt due within one year* ............................................. (1,701,072) (1,975,755)
-------------- --------------
Total long-term debt* ........................................................... 10,872,216 12,865,352
-------------- --------------
TOTAL CAPITALIZATION* ........................................................... $ 18,686,388 $ 21,339,001
- -----------------------------------------------------------------------------------------------------------------------
* 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.
39
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Restated)
ACCUMULATED
OTHER OTHER
COMPREHENSIVE NUMBER PAR PAID-IN COMPREHENSIVE
INCOME OF SHARES VALUE CAPITAL INCOME (LOSS)
------------- ------------- ------------- ------------- -------------
(DOLLARS IN THOUSANDS)
Balance, January 1, 2000 ................... 232,454,287 $ 23,245 $ 3,722,375 $ (195)
Net income .............................. $ 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
Cash dividends on common stock ..........
Balance, December 31, 2000 ................. 224,531,580 22,453 3,531,821 593
GPU acquisition ......................... 73,654,696 7,366 2,586,097
Net income .............................. $ 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 adjust-
ments, 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
Cash dividends on common stock ..........
Balance, December 31, 2001 ................. 297,636,276 29,764 6,113,260 (169,003)
Net income .............................. $ 552,804
Minimum liability for unfunded retirement
benefits, net of $(316,681,000) of
income taxes .......................... (449,615) (449,615)
Unrealized gain on derivative hedges, net
of $37,458,000 of income taxes ........ 59,187 59,187
Unrealized loss on investments, net of
$(4,266,000) of income taxes .......... (5,269) (5,269)
Unrealized currency translation adjust-
ments ................................. (91,448) (91,448)
-------------
Comprehensive income .................... $ 65,659
=============
Stock options exercised ................. (8,169)
Allocation of ESOP shares ............... 15,250
Cash dividends on common stock ..........
Balance, December 31, 2002 ................. 297,636,276 $ 29,764 $ 6,120,341 $ (656,148)
============= ============= ============= ===========
UNALLOCATED
ESOP
RETAINED COMMON
EARNINGS STOCK
------------- -------------
Balance, January 1, 2000 ................... $ 945,241 $ (126,776)
Net income .............................. 598,970
Minimum liability for unfunded
retirement benefits, net of
$85,000 of income taxes ...............
Unrealized gain on investment in
securities available for sale .........
Comprehensive income ....................
Reacquired common stock .................
Allocation of ESOP shares ............... 15,044
Cash dividends on common stock .......... (334,220)
-------------
Balance, December 31, 2000 ................. 1,209,991 (111,732)
GPU acquisition .........................
Net income .............................. 646,447
Minimum liability for unfunded retirement
benefits, net of $(182,000) of income
taxes .................................
Unrealized loss on derivative hedges, net
of $(116,521,000) of income taxes .....
Unrealized gain on investments, net of
$56,000 of income taxes ...............
Unrealized currency translation adjust-
ments, net of $(1,000) of income taxes
Comprehensive income ....................
Reacquired common stock .................
Allocation of ESOP shares ............... 14,505
Cash dividends on common stock .......... (334,633)
-------------
Balance, December 31, 2001 ................. 1,521,805 (97,227)
Net income .............................. 552,804
Minimum liability for unfunded retirement
benefits, net of $(316,681,000) of
income taxes ..........................
Unrealized gain on derivative hedges, net
of $37,458,000 of income taxes ........
Unrealized loss on investments, net of
$(4,266,000) of income taxes ..........
Unrealized currency translation adjust-
ments .................................
Comprehensive income ....................
Stock options exercised .................
Allocation of ESOP shares ............... 18,950
Cash dividends on common stock .......... (439,628)
-------------
Balance, December 31, 2002 ................. $ 1,634,981 (78,277)
============= =============
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
40
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, 2000 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
Redemptions-
7.75% Series (4,000,000) (100,000)
$7.56 Series B (450,000) (45,071)
$42.40 Series T (200,000) (96,850)
$8.32 Series (100,000) (10,000)
$7.76 Series (150,000) (15,000)
$7.80 Series (150,000) (15,000)
$10.00 Series (190,000) (19,000)
$2.21 Series (1,000,000) (25,000)
7.625% Series (7,500) (750)
$7.35 Series C (10,000) (1,000)
$90.00 Series S (17,750) (17,010)
8.65% Series J (250,001) (26,750)
7.52% Series K (265,000) (28,951)
9.00% Series (4,800,000) (120,000)
Amortization of fair market
value adjustments-
$ 7.35 Series C (9)
$90.00 Series S (258)
8.56% Series (6)
7.35% Series 209
7.34% Series 214
--------
Balance, December 31, 2002 6,209,699 $335,123 17,202,500 $430,138
========== ======== ========== ========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
41
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000
- -------------------------------- ----------- ----------- -----------
(SEE NOTES
2 (L) AND (M))
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...................................................... $ 552,804 $ 646,447 $ 598,970
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization................ 1,305,843 889,550 933,684
Nuclear fuel and lease amortization........................ 80,507 98,178 113,330
Other amortization, net (Note 2)........................... (16,593) (11,927) (11,635)
Deferred costs recoverable as regulatory assets............ (362,956) (31,893) --
Avon investment impairment (Note 3)........................ 50,000 -- --
Deferred income taxes, net................................. 56,732 31,625 (79,429)
Investment tax credits, net................................ (28,325) (22,545) (30,732)
Cumulative effect of accounting change..................... -- 14,338 --
Discontinued Operations (See Note 2(M)).................... 87,476 -- --
Receivables................................................ (85,307) 53,099 (150,520)
Materials and supplies..................................... (29,557) (50,052) (29,653)
Accounts payable........................................... 220,762 (84,572) 118,282
Deferred lease costs....................................... (84,800) -- --
Other (Note 9)............................................. 168,701 (250,564) 45,529
----------- ----------- -----------
Net cash provided from operating activities.............. 1,915,287 1,281,684 1,507,826
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Preferred stock.............................................. -- 96,739 --
Long-term debt............................................... 668,676 4,338,080 307,512
Short-term borrowings, net................................... 478,520 -- 281,946
Redemptions and Repayments-
Common stock................................................. -- (15,308) (195,002)
Preferred stock.............................................. (522,223) (85,466) (38,464)
Long-term debt............................................... (1,308,814) (394,017) (901,764)
Short-term borrowings, net................................... -- (1,641,484) --
Common Stock Dividend Payments.................................. (439,628) (334,633) (334,220)
----------- ----------- -----------
Net cash provided from (used for) financing activities... (1,123,469) 1,963,911 (879,992)
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
GPU acquisition, net of cash.................................... -- (2,013,218) --
Property additions.............................................. (997,723) (852,449) (587,618)
Proceeds from sale of Midlands.................................. 155,034 -- --
Avon cash and cash equivalents (Note 3)......................... 31,326 -- --
Net assets held for sale........................................ (31,326) -- --
Cash investments (Note 2)....................................... 81,349 24,518 17,449
Other (Note 9).................................................. (54,355) (233,526) (120,195)
----------- ----------- -----------
Net cash used for investing activities................... (815,695) (3,074,675) (690,364)
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents............ (23,877) 170,920 (62,530)
Cash and cash equivalents at beginning of year.................. 220,178 49,258 111,788
----------- ----------- -----------
Cash and cash equivalents at end of year*....................... $ 196,301 $ 220,178 $ 49,258
=========== =========== ===========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................ $ 881,515 $ 425,737 $ 485,374
Income taxes................................................. $ 389,180 $ 433,640 $ 512,182
* 2001 excludes amounts in "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.
42
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF TAXES
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 200O
- -------------------------------- ----------- ----------- -----------
RESTATED
(SEE NOTE 2(M))
(IN THOUSANDS)
GENERAL TAXES:
Real and personal property...................................... $ 218,683 $ 176,916 $ 281,374
State gross receipts*........................................... 132,622 102,335 221,385
Kilowatt-hour excise*........................................... 219,970 117,979 --
Social security and unemployment................................ 46,345 44,480 39,134
Other........................................................... 32,709 13,630 5,788
----------- ----------- -----------
Total general taxes...................................... $ 650,329 $ 455,340 $ 547,681
=========== =========== ===========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal...................................................... $ 326,417 $ 375,108 $ 467,045
State........................................................ 104,866 84,322 19,918
Foreign...................................................... 20,624 108 --
----------- ----------- -----------
451,908 459,538 486,963
----------- ----------- -----------
Deferred, net-
Federal...................................................... 81,934 37,888 (60,831)
State........................................................ 7,759 (6,177) (18,598)
Foreign...................................................... 13,600 (86) --
----------- ----------- -----------
103,293 31,625 (79,429)
----------- ----------- -----------
Investment tax credit amortization.............................. (26,507) (22,545) (30,732)
----------- ----------- -----------
Total provision for income taxes......................... $ 528,694 $ 468,618 $ 376,802
=========== =========== ===========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes................... $1,081,498 $ 1,115,065 $ 975,772
=========== =========== ===========
Federal income tax expense at statutory rate.................... $ 390,273 $ 341,520
Increases (reductions) in taxes resulting from- $ 378,524
Amortization of investment tax credits....................... (26,507) (22,545) (30,732)
State income taxes, net of federal income tax benefit........ 73,220 50,794 1,133
Amortization of tax regulatory assets........................ 29,296 30,419 38,702
Amortization of goodwill..................................... -- 18,416 18,420
Preferred stock dividends.................................... 13,634 19,733 18,172
Valuation reserve for tax benefits........................... 48,587 -- --
Other, net................................................... 11,440 (18,472) (10,413)
----------- ----------- -----------
Total provision for income taxes......................... $ 528,694 $ 468,618 $ 376,802
=========== =========== ===========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences.................................... $2,052,594 $ 1,996,937 $ 1,245,297
Customer receivables for future income taxes.................. 144,073 178,683 62,527
Competitive transition charge................................. 1,408,232 1,289,438 1,070,161
Deferred sale and leaseback costs............................. (99,647) (77,099) (128,298)
Nonutility generation costs................................... (228,476) (178,393) --
Unamortized investment tax credits............................ (78,227) (86,256) (85,641)
Unused alternative minimum tax credits........................ -- -- (32,215)
Other comprehensive income.................................... (240,663) (115,395) --
Above market leases........................................... (490,698) -- --
Other (Notes 2 and 9)......................................... (397,506) (323,696) (37,724)
----------- ----------- -----------
Net deferred income tax liability**.................... $2,069,682 $ 2,684,219 $ 2,094,107
=========== =========== ===========
* Collected from customers through regulated rates and included in revenue
on the Consolidated Statements of Income.
** 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.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL:
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). ATSI owns and operates FirstEnergy's transmission facilities
within the service areas of OE, CEI and TE (Ohio Companies) and Penn. The
utility subsidiaries are referred to throughout as "Companies." FirstEnergy's
2001 results include the results of JCP&L, Met-Ed and Penelec from the period
they were acquired on November 7, 2001 through December 31, 2001. The
consolidated financial statements also include FirstEnergy's other principal
subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services
Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; 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. FSG 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 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 Securities and Exchange Commission (SEC), 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 the 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, as described further in Notes 8 and 9.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(A) CONSOLIDATION-
FirstEnergy consolidates all majority-owned subsidiaries, after
eliminating the effects of intercompany transactions. Non-majority owned
investments, including investments in limited liability companies, partnerships
and joint ventures, are accounted for under the equity method when FirstEnergy
is able to influence their financial or operating policies. Investments in
corporations resulting in voting control of 20% or more are presumed to be
equity method investments. Limited partnerships are evaluated in accordance with
SEC Staff D-46, "Accounting for Limited Partnership Investments" and American
Institute of Certified Public Accountants (AICPA) Statement of Position (SOP)
78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to
5 percent threshold for the presumption of influence. For all remaining
investments (excluding those within the scope of Statement of Financial
Accounting Standards (SFAS) 115, FirstEnergy applies the cost method.
(B) EARNINGS PER SHARE-
Basic earnings per share are computed using the weighted average of
actual common shares outstanding as the denominator. Diluted earnings per share
reflect the weighted average of actual common shares outstanding plus the
potential additional common shares that could result if dilutive securities and
agreements were exercised in the denominator. In 2002, 2001 and 2000, stock
based awards to purchase shares of common stock totaling 3.4 million, 0.1
million and 1.8 million, respectively, were excluded from the calculation of
diluted earnings per share of common stock because their exercise prices were
greater than the average market price of common shares during the period. The
numerators for the calculations of basic and diluted earnings per share are
Income Before Cumulative Effect of Changes in Accounting and Net Income. The
following table reconciles the denominators for basic and diluted earnings per
share:
DENOMINATOR FOR EARNINGS PER SHARE CALCULATIONS
- -----------------------------------------------
YEARS ENDED DECEMBER 31,
2002 2001 2000
------- ------- -------
(IN THOUSANDS)
Denominator for basic earnings per share
(weighted average shares actually outstanding) 293,194 229,512 222,444
Assumed exercise of dilutive securities or
agreements to issue common stock 1,227 918 282
------- ------- -------
Denominator for diluted earnings per share 294,421 230,430 222,726
======= ======= =======
44
(C) 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. See Note 9 - Other Information for
discussion of reporting of independent system operator (ISO) transactions.
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, 2002 or 2001, with respect to
any particular segment of FirstEnergy's customers.
CEI and TE sell substantially all of their retail customers'
receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of
CEI. CFC subsequently transfers the receivables to a trust (an SFAS 140
"qualified special purpose entity") under an asset-backed securitization
agreement. Transfers are made in return for an interest in the trust (41% as of
December 31, 2002), which is stated at fair value, reflecting adjustments for
anticipated credit losses. The average collection period for billed receivables
is 28 days. Given the short collection period after billing, the fair value of
CFC's interest in the trust approximates the stated value of its retained
interest in underlying receivables after adjusting for anticipated credit
losses. Accordingly, subsequent measurements of the retained interest under SFAS
115 (as an available-for-sale financial instrument) result in no material change
in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of
anticipated credit losses would not have significantly affected FirstEnergy's
retained interest in the pool of receivables through the trust. Of the $272
million sold to the trust and outstanding as of December 31, 2002, FirstEnergy's
retained interests in $111 million of the receivables are included as other
receivables on the Consolidated Balance Sheets. Accordingly, receivables
recorded on the Consolidated Balance Sheets were reduced by approximately $161
million due to these sales. Collections of receivables previously transferred to
the trust and used for the purchase of new receivables from CFC during 2002
totaled approximately $2.2 billion. CEI and TE processed receivables for the
trust and received servicing fees of approximately $3.8 million in 2002.
Expenses associated with the factoring discount related to the sale of
receivables were $4.7 million in 2002.
In June 2002, the Emerging Issues Task Force (EITF) reached a partial
consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." Based on the EITF's partial consensus position, for
periods after July 15, 2002, mark-to-market revenues and expenses and their
related kilowatt-hour (KWH) sales and purchases on energy trading contracts must
be shown on a net basis in the Consolidated Statements of Income. FirstEnergy
has previously reported such contracts as gross revenues and purchased power
costs. Comparative quarterly disclosures and the Consolidated Statements of
Income for revenues and expenses have been reclassified for 2002 only to conform
with the revised presentation (see Note 11 - Summary of Quarterly Financial
Data). In addition, the related KWH sales and purchases statistics described
under Management's Discussion and Analysis - Results of Operations were
reclassified (7.2 billion KWH in 2002 and 3.7 billion KWH in 2001). The
following table displays the impact of changing to a net presentation for
FirstEnergy's energy trading operations.
2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES
- ------------------------------------------- -------- --------
RESTATED
(SEE NOTES 2(L) AND 2(M))
(IN MILLIONS)
Total before adjustment $12,499 $10,368
Adjustment (268) (268)
------- --------
Total as reported $12,231 $10,100
======= ========
(D) REGULATORY MATTERS-
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in the
Companies' respective state regulatory plans:
- allowing the Companies' electric customers to select their
generation suppliers;
- establishing provider of last resort (PLR) obligations to
customers in the Companies' service areas;
- allowing recovery of potentially stranded investment (or
transition costs);
- itemizing (unbundling) the price of electricity into its component
elements - including generation, transmission, distribution and
stranded costs recovery charges;
- deregulating the Companies' electric generation businesses; and
45
- continuing regulation of the Companies' transmission and
distribution systems.
Ohio
In July 1999, Ohio's electric utility restructuring legislation, which
allowed Ohio electric customers to select their generation suppliers beginning
January 1, 2001, was signed into law. Among other things, the legislation
provided for a 5% reduction on the generation portion of residential customers'
bills and the opportunity to recover transition costs, including regulatory
assets, from January 1, 2001 through December 31, 2005 (market development
period). The period for the recovery of regulatory assets only can be extended
up to December 31, 2010. The PUCO was authorized to determine the level of
transition cost recovery, as well as the recovery period for the regulatory
assets portion of those costs, in considering each Ohio electric utility's
transition plan application.
In July 2000, the PUCO approved FirstEnergy's transition plan for the
Ohio Companies as modified by a settlement agreement with major parties to the
transition plan. The application of SFAS 71, "Accounting for the Effects of
Certain Types of Regulation" to OE's generation business and the nonnuclear
generation businesses of CEI and TE was discontinued with the issuance of the
PUCO transition plan order, as described further below. Major provisions of the
settlement agreement consisted of approval of recovery of generation-related
transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6
billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to
regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0
billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery 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 generation-related
transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0
billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets
recognized as regulatory assets as described further below, $2.4 billion, net of
deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion)
of above market operating lease costs (see Note 2(M) for consideration of above
market lease costs) and $0.8 billion, net of deferred income taxes, (CEI-$0.5
billion and TE-$0.3 billion) of additional plant costs that were reflected on
CEI's and TE's regulatory financial statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 1,120 megawatts (MW) of generation capacity through 2005 at
established prices for sales to the Ohio Companies' retail customers. Customer
prices are frozen through the five-year market development period except for
certain limited statutory exceptions, including the 5% reduction referred to
above. In February 2003, the Ohio Companies were authorized increases in annual
revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million
and TE-$5 million) to recover their higher tax costs resulting from the Ohio
deregulation legislation.
FirstEnergy's Ohio customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
respective transition cost recovery period. If the customer shopping goals
established in the agreement had not been achieved by the end of 2005, the
transition cost recovery periods could have been 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). The Ohio Companies achieved all of their required
20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that
there will be no regulatory action reducing the recoverable transition costs.
New Jersey
JCP&L's 2001 Final Decision and Order (Final Order) with respect to its
rate unbundling, stranded cost and restructuring filings confirmed rate
reductions set forth in its 1999 Summary Order, which remain in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable societal benefits charge (SBC) 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. The NJBPU has 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
customers, there would be no effect to FirstEnergy's or JCP&L's net income since
the contingency existed prior to the merger.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
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 provided for a usage-based non-bypassable transition bond charge and
for the transfer of the bondable transition property to another entity. JCP&L
sold $320 million of transition bonds through its wholly owned subsidiary, JCP&L
Transition Funding LLC, in June 2002 - those bonds are recognized on the
Consolidated Balance Sheet (see Note 5).
JCP&L's PLR obligation to provide basic generation service (BGS) to
non-shopping customers is supplied 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
46
nonutility generation (NUG) agreements exceed amounts collected through BGS and
MTC rates. As of December 31, 2002, the accumulated deferred cost balance
totaled approximately $549 million. The NJBPU also allowed 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.
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. On August 1, 2002, JCP&L
submitted two rate filings with the NJBPU. The first filing requested increases
in base electric rates of approximately $98 million annually. The second filing
was a request to recover deferred costs that exceeded amounts being recovered
under the current MTC and SBC rates; one proposed method of recovery of these
costs is the securitization of the deferred balance. This securitization
methodology is similar to the Oyster Creek securitization discussed above.
Hearings began in February 2003. The Administrative Law Judge's recommended
decision is due in June 2003 (see Note 13) and the NJBPU's subsequent decision
is due in July 2003.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The auction
results were approved by the NJBPU in February 2002, removing JCP&L's BGS
obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In
February 2003, the NJBPU approved the BGS auction results for the period
beginning August 1, 2003. The auction covered a fixed price bid (applicable to
all residential and smaller commercial and industrial customers) and an hourly
price bid (applicable to all large industrial customers) process. JCP&L will
sell all self-supplied energy (NUGs and owned generation) to the wholesale
market with offsets to its deferred energy cost balances.
Pennsylvania
The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and
Penelec. 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 customers. Similar to JCP&L's situation,
if the IRS ruling ultimately supports returning these tax benefits to customers,
there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income
since the contingency existed prior to the merger.
As a result of their generating asset divestitures, Met-Ed and Penelec
obtained their supply of electricity to meet their PLR obligations almost
entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec
filed a petition with the PPUC seeking permission to defer, for future recovery,
energy costs in excess of amounts reflected in their capped generation rates;
the PPUC subsequently consolidated this petition in January 2001 with the
FirstEnergy/GPU merger proceeding.
In June 2001, the PPUC entered orders approving the Settlement
Stipulation with all of the major parties in the combined merger and rate relief
proceedings which approved the merger and provided Met-Ed and Penelec PLR
deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and
Penelec 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. Correspondingly, in the event that energy costs incurred by
Met-Ed and Penelec would be below their respective capped generation rates, that
difference would have reduced costs that had been deferred for recovery in
future periods. This PLR deferral accounting procedure was denied in a court
decision discussed below. Met-Ed's and Penelec's PLR obligations extend through
December 31, 2010; during that period competitive transition charge (CTC)
revenues would have been applied to their stranded costs. Met-Ed and Penelec
would have been permitted to recover any remaining stranded costs through a
continuation of the CTC after December 31, 2010 through no later than December
31, 2015. Any amounts not expected to be recovered by December 31, 2015 would
have been written off at the time such nonrecovery became probable.
Several parties had filed Petitions for Review in June and July 2001
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC 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 rejected those parts of the
settlement that permitted the companies to defer for accounting purposes the
difference between their wholesale power costs and the amount that they collect
from retail customers. FirstEnergy and the PPUC each filed a Petition for
Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002,
asking it to review the Commonwealth Court decision. Also on March 25, 2002,
Citizens Power filed a motion seeking an appeal of the Commonwealth Court's
decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme
Court. In September 2002, FirstEnergy established reserves for Met-Ed's and
Penelec's PLR deferred energy costs which aggregated $287.1 million. The
reserves reflected the potential adverse impact of a pending Pennsylvania
Supreme Court decision whether to review the Commonwealth Court ruling.
FirstEnergy recorded an aggregate non-cash charge of $55.8 million ($32.6
million net of tax) to income for the deferred costs incurred subsequent to the
merger. The reserve for the remaining $231.3 million of deferred costs increased
goodwill by an aggregate net of tax amount of $135.3 million.
47
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which
effectively affirmed the PPUC's order approving the merger between FirstEnergy
and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed
and Penelec and remanded the merger savings issue back to the PPUC. Because
FirstEnergy had already reserved for the deferred energy costs and FES has
largely hedged the anticipated PLR energy supply requirements for Met-Ed and
Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and Penelec
believe that the disallowance of CTC recovery of PLR costs above Met-Ed's and
Penelec's capped generation rates will not have a future adverse financial
impact.
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to their FES affiliate through a wholesale power sale agreement.
The PLR sale, which initially ran through the end of 2002, was extended through
December 2003 and will be automatically extended for each successive calendar
year unless any party elects to cancel the agreement by November 1 of the
preceding year. Under the terms of the wholesale agreement, FES assumes the
supply obligation and the energy supply profit and loss risk, for the portion of
power supply requirements not self-supplied by Met-Ed and Penelec under their
NUG contracts and other existing power contracts with nonaffiliated third party
suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high
wholesale power prices by providing power at or below the shopping credit for
their uncommitted PLR energy costs during the term of the agreement with FES.
FES has hedged most of Met-Ed's and Penelec's unfilled PLR obligation through
2005, the period during which deferred accounting was previously allowed under
the PPUC's order. Met-Ed and Penelec are authorized to continue deferring
differences between NUG contract costs and amounts recovered through their
capped generation rates.
The application of SFAS 71 has been discontinued with respect to the
Companies' generation operations. The SEC issued interpretive guidance regarding
asset impairment measurement, concluding that any supplemental regulated cash
flows such as a 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,
$1.8 billion of impaired plant investments ($1.2 billion, $227 million, $304
million and $53 million for OE, Penn, 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, 2002.
SFAS 71
DISCONTINUED
NET ASSETS TOTAL ASSETS
------------ ------------
(IN MILLIONS)
OE $ 947 $7,740
CEI 1,406 6,510
TE 559 2,862
Penn 82 908
JCP&L 44 8,053
Met-Ed 17 3,565
Penelec -- 3,163
(E) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment reflects original cost (except for
nuclear generating units and the international properties which were adjusted to
fair value), including payroll and related costs such as taxes, employee
benefits, administrative and general costs, and interest costs. JCP&L holds a
50% ownership interest in Yards Creek Pumped Storage Facility - its net book
value was approximately $21.3 million as of December 31, 2002. FirstEnergy also
shares ownership interests in various foreign properties with an aggregate net
book value of $154 million, representing the fair value of FirstEnergy's
interest. FirstEnergy's accounting policy for planned major maintenance projects
is to recognize liabilities as they are incurred.
The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The respective annual composite rates for the Companies' electric plant in 2002,
2001 and 2000 (post merger periods only for JCP&L, Met-Ed and Penelec) are shown
in the following table:
48
ANNUAL COMPOSITE
DEPRECIATION RATE
-------------------------
2002 2001 2000
---- ---- ----
OE 2.7% 2.7% 2.8%
CEI 3.4 3.2 3.4
TE 3.9 3.5 3.4
Penn 2.9 2.9 2.6
JCP&L 3.5 3.4
Met-Ed 3.0 3.0
Penelec 3.0 2.9
Annual depreciation expense in 2002 included approximately $125 million
for future decommissioning costs applicable to the Companies' ownership and
leasehold interests in five nuclear generating units (Davis-Besse Unit 1, Beaver
Valley Units 1 and 2, Perry Unit 1 and Three Mile Island Unit 2 (TMI-2)), a
demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a
wholly-owned subsidiary of JCP&L, Met-Ed and Penelec, and decommissioning
liabilities for previously divested GPU nuclear generating units. The Companies'
share of the future obligation to decommission these units is approximately $2.6
billion in current dollars and (using a 4.0% escalation rate) approximately $5.3
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 $671 million for decommissioning through their electric
rates from customers through December 31, 2002. The Companies have also
recognized an estimated liability of approximately $37 million related to
decontamination and decommissioning of nuclear enrichment facilities operated by
the United States Department of Energy, as required by the Energy Policy Act of
1992.
In June 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations". The new statement provides accounting standards for
retirement obligations associated with tangible long-lived assets, with adoption
required by January 1, 2003. SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recorded in the period in which
it is incurred. The associated asset retirement costs are capitalized as part of
the carrying amount of the long-lived asset. Over time the capitalized costs are
depreciated and the present value of the asset retirement liability increases,
resulting in a period expense. However, rate-regulated entities may recognize a
regulatory asset or liability if the criteria for such treatment are met. Upon
retirement, a gain or loss would be recorded if the cost to settle the
retirement obligation differs from the carrying amount.
FirstEnergy has identified applicable legal obligations as defined
under the new standard, principally for nuclear power plant decommissioning.
Upon adoption of SFAS 143, asset retirement costs of $602 million were recorded
as part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $415 million. Due to the increased carrying amount,
the related long-lived assets were tested for impairment in accordance with SFAS
144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment
was indicated.
The asset retirement liability at the date of adoption will be $1.109
billion. As of December 31, 2002, FirstEnergy had recorded decommissioning
liabilities of $1.243 billion. The change in the estimated liabilities resulted
from changes in methodology and various assumptions, including changes in the
projected dates for decommissioning.
Management expects that the ultimate nuclear decommissioning costs for
Met-Ed, Penelec, JCP&L and Penn will be tracked and recovered through their
regulated rates. Therefore, FirstEnergy recognized a regulatory liability of
$185 million upon adoption of SFAS 143 for the transition amounts related to
establishing the asset retirement obligations for nuclear decommissioning for
those companies. The remaining cumulative effect adjustment to recognize the
undepreciated asset retirement cost and the asset retirement liability offset by
the reversal of the previously recorded decommissioning liabilities was a $175
million increase to income ($102 million net of tax).
The 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 ceased January 1, 2002. Instead, goodwill is
tested for impairment at least on an annual basis - based on the results of the
transition analysis and the 2002 annual analysis, no impairment of FirstEnergy's
goodwill is required. The impairment analysis includes a significant source of
cash representing EUOC recovery of transition costs as described above under
"Regulatory Matters." FirstEnergy does not believe that completion of transition
cost recovery will result in an impairment of goodwill relating to its regulated
business segment. Prior to the adoption of SFAS 142, FirstEnergy amortized about
$57 million ($.23 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.
49
The following table displays what net income and earnings per share
would have been if goodwill amortization had been excluded in 2001 and 2000:
2002 2001 2000
-------- -------- --------
RESTATED
(SEE NOTE 2(M))
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Reported net income.............................. $552,804 $646,447 $598,970
Goodwill amortization (net of tax)............... -- 54,584 54,138
-------- -------- --------
Adjusted net income.............................. $552,804 $701,031 $653,108
======== ======== ========
Basic earnings per common share:
Reported earnings per share................... $1.89 $2.82 $2.69
Goodwill amortization......................... -- 0.23 0.25
-------- -------- --------
Adjusted earnings per share................... $1.89 $3.05 $2.94
======== ======== ========
Diluted earnings per common share:
Reported earnings per share................... $1.88 $2.81 $2.69
Goodwill amortization......................... -- 0.23 0.24
-------- -------- --------
Adjusted earnings per share................... $1.88 $3.04 $2.93
======== ======== ========
The net change of $677 million in the goodwill balance as of December 31, 2002
compared to the December 31, 2001 balance primarily reflects the $135.3 million
after-tax effect of the Pennsylvania PLR reserve discussed in Note 2D -
Regulatory Matters - Pennsylvania and finalization of the initial purchase price
allocation for the GPU acquisition (see Note 12).
(F) NUCLEAR FUEL-
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. The
Companies amortize the cost of nuclear fuel based on the rate of consumption.
(G) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 5C). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the fair
value method, a higher value would have been assigned to the options granted.
The weighted average assumptions used in valuing the options and their resulting
estimated fair values would be as follows:
2002 2001 2000
----- ----- -----
Valuation assumptions:
Expected option term (years) 8.1 8.3 7.6
Expected volatility 23.31% 23.45% 21.77%
Expected dividend yield 4.36% 5.00% 6.68%
Risk-free interest rate 4.60% 4.67% 5.28%
Fair value per option $6.45 $4.97 $2.86
The effects of applying fair value accounting to the FirstEnergy's
stock options would be to reduce net income and earnings per share. The
following table summarizes this effect.
50
2002 2001 2000
-------- -------- --------
RESTATED
(SEE NOTE 2(M)
(IN THOUSANDS)
Net Income, as reported $552,804 $646,447 $598,970
Add back compensation expense
reported in net income, net of tax
(based on APB 25) 166 25 144
Deduct compensation expense based
upon fair value, net of tax (8,825) (3,748) (1,736)
-------- -------- --------
Adjusted net income $544,145 $642,724 $597,378
-------- -------- --------
Earnings Per Share of Common Stock -
Basic
As Reported $ 1.89 $ 2.82 $ 2.69
Adjusted $ 1.86 $ 2.80 $ 2.69
Diluted
As Reported $ 1.88 $ 2.81 $ 2.69
Adjusted $ 1.85 $ 2.79 $ 2.69
(H) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and accounting
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred income taxes. Deferred income tax liabilities
related to tax and accounting basis differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid.
Valuation allowances of $465 million were established and included in the
Consolidated Balance Sheet as of December 31, 2002, primarily associated with
certain fair value adjustments (see Note 12) and capital losses related to the
divestitures of international assets owned by the former GPU, Inc. prior to its
acquisition by FirstEnergy. Of the total valuation allowance, $325 million
relates to capital loss carryforwards that expire at the end of 2007. Management
is unable to predict whether sufficient capital gains will be generated to
utilize all of these capital loss carryforwards. Any ultimate utilization of
these capital loss carryforwards for which valuation allowances have been
established would reduce goodwill.
(I) 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, 2002.
The assets of the pension plan consist primarily of common stocks, United States
government bonds and corporate bonds. 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 contributions, 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.
As a result of the reduced market value of FirstEnergy's pension plan
assets, it was required to recognize an additional minimum liability as
prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and
Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated
benefit obligation of $3.438 billion exceeded the fair value of plan assets
($2.889 billion) resulting in a minimum pension liability of $548.6 million.
FirstEnergy eliminated its prepaid pension asset of $286.9 million and
established a minimum liability of $548.6 million, recording an intangible asset
of $78.5 million and reducing OCI by $444.2 million (recording a related
deferred tax asset of $312.8 million). The charge to OCI will reverse in future
periods to the extent the fair value of trust assets exceed the accumulated
benefit obligation. The amount of pension liability recorded as of December 31,
2002, increased due to the lower discount rate and asset returns assumed as of
December 31, 2002.
51
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
------------------------ ------------------------
2002 2001 2002 2001
--------- --------- --------- ---------
(IN MILLIONS)
Change in benefit obligation:
Benefit obligation as of January 1 $ 3,547.9 $ 1,506.1 $ 1,581.6 $ 752.0
Service cost 58.8 34.9 28.5 18.3
Interest cost 249.3 133.3 113.6 64.4
Plan amendments -- 3.6 (121.1) --
Actuarial loss 268.0 123.1 440.4 73.3
Voluntary early retirement program -- -- -- 2.3
GPU acquisition (Note 12) (11.8) 1,878.3 110.0 716.9
Benefits paid (245.8) (131.4) (83.0) (45.6)
--------- --------- --------- ---------
Benefit obligation as of December 31 3,866.4 3,547.9 2,070.0 1,581.6
--------- --------- --------- ---------
Change in fair value of plan assets:
Fair value of plan assets as of January 1 3,483.7 1,706.0 535.0 23.0
Actual return on plan assets (348.9) 8.1 (57.1) 12.7
Company contribution -- -- 37.9 43.3
GPU acquisition -- 1,901.0 -- 462.0
Benefits paid (245.8) (131.4) (42.5) (6.0)
--------- --------- --------- ---------
Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0
--------- --------- --------- ---------
Funded status of plan (977.4) (64.2) (1,596.7) (1,046.6)
Unrecognized actuarial loss 1,185.8 222.8 751.6 212.8
Unrecognized prior service cost 78.5 87.9 (106.8) 17.7
Unrecognized net transition obligation -- -- 92.4 101.6
--------- --------- --------- ---------
Net amount recognized $ 286.9 $ 246.5 $ (859.5) $ (714.5)
========= ========= ========= =========
Consolidated Balance Sheets classification:
Prepaid (accrued) benefit cost $ (548.6) $ 246.5 $ (859.5) $ (714.5)
Intangible asset 78.5 -- -- --
Accumulated other comprehensive loss 757.0 -- -- --
--------- --------- --------- ---------
Net amount recognized $ 286.9 $ 246.5 $ (859.5) $ (714.5)
========= ========= ========= =========
Assumptions used as of December 31:
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected long-term return on plan assets 9.00% 10.25% 9.00% 10.25%
Rate of compensation increase 3.50% 4.00% 3.50% 4.00%
Net pension and other postretirement benefit costs for the three
years ended December 31, 2002 were computed as follows:
OTHER
PENSION BENEFITS POSTRETIREMENT BENEFITS
------------------------ ------------------------
2002 2001 2000 2002 2001 2000
------ ------ ------ ------ ------ ------
(IN MILLIONS)
Service cost $ 58.8 $ 34.9 $ 27.4 $ 28.5 $ 18.3 $ 11.3
Interest cost 249.3 133.3 104.8 113.6 64.4 45.7
Expected return on plan assets (346.1) (204.8) (181.0) (51.7) (9.9) (0.5)
Amortization of transition obligation (asset) -- (2.1) (7.9) 9.2 9.2 9.2
Amortization of prior service cost 9.3 8.8 5.7 3.2 3.2 3.2
Recognized net actuarial loss (gain) -- -- (9.1) 11.2 4.9 --
Voluntary early retirement program -- 6.1 17.2 -- 2.3 --
------ ------ ------ ------ ------ ------
Net periodic benefit cost (income) $(28.7) $(23.8) $(42.9) $114.0 $ 92.4 $ 68.9
====== ====== ====== ====== ====== ======
The composite health care cost trend rate assumption is
approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in
later years. Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plan. An increase in the health care
cost trend rate assumption by one percentage point would increase the total
service and interest cost components by $20.7 million and the postretirement
benefit obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
(J) 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. As of
December 31, 2002, cash and cash equivalents included $50 million used for the
redemption of long-term debt in January 2003. 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
and $89.3 million for the years 2001 and 2000,
52
respectively. There were no capital lease transactions in 2002. Commercial paper
transactions of OES Fuel, Incorporated (a wholly owned subsidiary of OE) that
had initial maturity periods of three months or less were reported net within
financing activities under long-term debt, prior to the expiration of the
related long-term financing agreement in March 2002, and were reflected as
currently payable long-term debt on the Consolidated Balance Sheet as of
December 31, 2001. Net losses on foreign currency exchange transactions
reflected in FirstEnergy's 2002 Consolidated Statement of Income consisted of
approximately $104.1 million from FirstEnergy's Argentina operations (see Note 3
- - Divestitures).
In the Consolidated Statements of Cash Flows, the amounts included
in "Cash investments" under Net cash used for Investing Activities primarily
consist of changes in capital trust investments of $(87) million (see Note 4 -
Leases) and other cash investments of $6 million. The amounts included in "Other
amortization, net" under Net cash provided from Operating Activities primarily
consist of amounts from the reduction of an electric service obligation under a
CEI electric service prepayment program.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt, preferred stock subject to mandatory redemption and
investments other than cash and cash equivalents as of December 31:
2002 2001
------------------- -------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- -------- -------- --------
(IN MILLIONS)
Long-term debt* $ 12,465 $ 12,761 $ 12,897 $ 13,097
Preferred stock $ 445 $ 454 $ 636 $ 626
Investments other than cash
and cash equivalents:
Debt securities:
- Maturity (5-10 years) $ 502 $ 471 $ 439 $ 402
- Maturity (more than 10 years) 927 1,030 990 1,009
Equity securities 15 15 15 15
All other 1,668 1,669 1,730 1,734
-------- -------- -------- --------
$ 3,112 $ 3,185 $ 3,174 $ 3,160
======== ======== ======== ========
* Excluding approximately $1.75 billion of long-term debt in 2001 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.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Companies have no securities held for trading purposes.
See Note 9 - Other Information for discussion of SFAS 115 activity
related to equity investments.
The investment policy for the nuclear decommissioning trust funds
restricts or limits the ability to hold certain types of assets including
private or direct placements, warrants, securities of FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "All other" in the
table above) consist of equity securities, government bonds and corporate bonds.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in the trust investment with a corresponding change to the
decommissioning liability. In conjunction with the adoption of SFAS 143 on
January 1, 2003, unrealized gains or losses were reclassified to OCI in
accordance with SFAS 115. Realized gains (losses) are recognized as additions
(reductions) to trust asset balances. For the year 2002, net realized gains
(losses) were approximately $(15.6) million and interest and dividend income
totaled approximately $33.2 million.
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 year ended
December 31, 2000 would not have been materially different if this accounting
had been in effect during that year.
53
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 and interest
rate 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. Also, gains and losses are included in net income when
ineffectiveness occurs on certain natural gas hedges. The impact of
ineffectiveness on earnings during 2002 was not material. 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. Gains and losses from derivative contracts are included in
other operating expenses. The current net deferred loss of $110.2 million
included in Accumulated Other Comprehensive Loss (AOCL) as of December 31, 2002,
for derivative hedging activity, as compared to the December 31, 2001 balance of
$169.4 million in net deferred losses, resulted from the reversal of $6.0
million of derivative losses related to the sale of Avon, a $33.0 million
reduction related to current hedging activity and a $20.2 million reduction due
to net hedge gains included in earnings during the year. Approximately $19.0
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. FirstEnergy also entered into fixed-to-floating interest rate swap
agreements during 2002 to increase the variable-rate component of its debt
portfolio from 16% to approximately 20% at year end. These derivatives are
treated as fair value hedges of fixed-rate, long-term debt issues-protecting
against the risk of changes in the fair value of fixed-rate debt instruments due
to lower interest rates. Swap maturities, call options and interest payment
dates match those of the underlying obligations resulting in no ineffectiveness
in these hedge positions. After reaching a maximum notional position of $993.5
million in the third quarter of 2002, FirstEnergy unwound $400 million of these
swaps in the fourth quarter of 2002 during a period of steadily declining market
interest rates. Gains recognized from unwinding these swaps were added to the
carrying value of the hedged debt and will be recognized over the remaining life
of the underlying debt (through November 2006).
FirstEnergy engages in the trading of commodity derivatives and
periodically experiences net open positions. FirstEnergy's risk management
policies limit the exposure to market risk from open positions and require daily
reporting to management of potential financial exposures.
(K) 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 as additional regulatory asset amortization in accordance
with their prior Ohio and current Pennsylvania regulatory plans.
54
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2002 2001
-------- --------
RESTATED
(SEE NOTE 2(M))
(IN MILLIONS)
Regulatory transition charge $7,795.7 $7,751.5
Customer receivables for future income taxes 394.0 433.0
Societal benefits charge 143.8 166.6
Loss on reacquired debt 73.7 80.0
Employee postretirement benefit costs 87.7 98.6
Nuclear decommissioning, decontamination and
spent fuel disposal costs 98.8 80.2
Provider of last resort costs -- 116.2
Property losses and unrecovered plant costs 87.8 104.1
Other 71.9 82.4
-------- --------
Total $8,753.4 $8,912.6
-------- --------
(L) CHANGE IN INCOME STATEMENT CLASSIFICATIONS -
FirstEnergy recorded a net charge to income during the year ended
December 31, 2002 of $57.1 million (net of income taxes of $13.6 million)
relative to decisions to retain interests in the Avon and Emdersa businesses
previously classified as held for sale - see Note 3. This net charge represents
the aggregate results of operations of Avon and Emdersa for the respective
periods these businesses were held for sale. This charge was previously reported
on the Consolidated Statement of Income as cumulative effect of a change in
accounting. In April 2003 it was determined that charge should instead have been
classified in operations. As further, discussed in Note 3, the decision to
retain Avon and Emdersa were made in the first and fourth quarters,
respectively, of the year ended 2002. The results of operations for these
businesses for the quarters in which the decisions were made to retain them have
been classified in their respective revenue and expense captions on the
Consolidated Statement of Income for the year ended December 31, 2002. The
aggregate results of operations for periods preceding the periods in which the
decision was made to retain Emdersa has been recorded net on the Consolidated
Statement of Income as a "Cumulative Adjustment for Retained Businesses
Previously Held for Sale. This change in classification had no effect on
previously reported net income. The effects of this change on the Consolidated
Statement of Income previously reported for the year ended December 31, 2002 are
as follows:
AS PREVIOUSLY REVISED
PRESENTED PRESENTATION*
------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues $ 12,151,997 $ 12,247,401
Expenses 9,969,814 9,995,740
Cumulative adjustment for retained businesses previously held for sale -- (93,723)
------------- -------------
Income before interest and income taxes 2,182,183 2,157,938
Net interest charges 946,306 965,582
Income taxes 549,476 563,076
Income before cumulative effect of accounting change 686,401 629,280
Cumulative effect of accounting change (57,121) --
------------- -------------
Net income $ 629,280 $ 629,280
------------- -------------
Basic Earnings Per Share:
Income before cumulative effect of accounting change $ 2.34 $ 2.15
Cumulative effect of accounting change (0.19) --
------------- -------------
Net income $ 2.15 $ 2.15
============= =============
Diluted Earnings Per Share:
Income before cumulative effect of accounting change $ 2.33 $ 2.14
Cumulative effect of accounting change (0.19) --
------------- -------------
Net income $ 2.14 $ 2.14
============= =============
* Revised as discussed above and filed on Form 10-K/A Amendment No. 1.
Excludes effect of restatements discussed in note 1(M) below.
(M) RESTATEMENTS
The Company is restating its financial statements for the year ended
December 31, 2002. The primary modifications include revisions to reflect a
change in the method of amortizing costs being recovered under the Ohio
transition plan and recognition of above-market values of certain leased
generation facilities. In addition, certain other immaterial adjustments related
to the recognition of a valuation allowance on a tax benefit recognized in 2002
and other adjustments are now reflected in results for the year ended December
31, 2002.
55
Transition Cost Amortization -
As discussed above under Regulatory Matters in Note 2(D),
FirstEnergy, OE, CEI and TE amortize transition costs using the effective
interest method. The amortization schedules originally developed at the
beginning of the transition plan in 2001 in applying this method were based on
total transition revenues, including revenues designed to recover costs which
have not yet been incurred or that were recognized on the regulatory financial
statements, but not in the financial statements prepared under GAAP. The Ohio
companies have revised the amortization schedules under the effective interest
method to consider only revenues relating to transition regulatory assets
recognized on the GAAP balance sheet. The impact of this change will result in
higher amortization of these regulatory assets in the first several years of the
transition cost recovery period compared with the method previously applied. The
change in method results in no change in total amortization of the previously
recorded regulatory assets recovered under the transition plan through the end
of 2009.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE
and Centerior. The merger was accounted for as an acquisition of Centerior, the
parent company of CEI and TE, under the purchase accounting rules of APB 16. In
connection with the reassessment of the accounting for the Transition Plan, the
Company reassessed its accounting for the Centerior purchase and determined that
above-market lease liabilities should have been recorded at the time of the
merger. Accordingly, as of 2002, the Company recorded additional adjustments
associated with the 1997 merger between OE and Centerior to reflect certain
above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield
Plant, for which CEI and TE had previously entered into sale-leaseback
arrangements. CEI and TE recorded an increase in goodwill related to the above
market lease costs for Beaver Valley Unit 2 because regulatory accounting for
nuclear generating assets had been discontinued prior to the merger date and it
was determined that this additional liability would have increased goodwill at
the date of the merger. The corresponding impact of the above-market lease
liability for the Bruce Mansfield Plant was recorded as a regulatory asset since
regulatory accounting had not been discontinued at that time for the fossil
generating assets and recovery of these liabilities was provided under the
Company's regulatory plan in effect at the time of the merger and subsequently
under the transition plan.
The total above-market lease obligation of $722 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017 (approximately $37 million per year). The additional goodwill has been
recorded on a net basis, reflecting amortization that would have been recorded
through 2001, when goodwill amortization ceased with the adoption of SFAS 142.
The total above market lease obligation of $755 million associated with the
Bruce Mansfield Plant is being amortized through the end of 2016 (approximately
$48 million per year). Before the start of the Transition Plan in fiscal 2001,
the regulatory asset would have been amortized at the same rate as the lease
obligation. Beginning in 2001, the remaining unamortized regulatory asset would
have been included in CEI's and TE's amortization schedules for regulatory
assets and amortized through the end of the recovery period - 2009 for CEI and
2007 for TE.
FirstEnergy has reflected the net impact of the accounting for these
items for the period from the merger in 1997 through 2001 in the 2002 financial
statements. The cumulative impact to net income recorded in 2002 related to
these prior periods increased net income by $5.9 million in the restated 2002
financial statements and is reflected as a reduction in other operating expenses
in the accompanying consolidated statement of income. In addition, the impact
increased the following balances in the consolidated balance sheet as of January
1, 2002:
INCREASE (DECREASE) (IN THOUSANDS)
Goodwill............................ $ 381,780
Regulatory assets................... 636,100
-----------
Total assets........................ $1,017,880
==========
Other current liabilities........... 84,600
Deferred income taxes............... (262,580)
Deferred investment tax credits..... (828)
Other deferred credits.............. 1,190,800
-----------
Total liabilities................... $1,011,992
==========
The adjustments were not reflected in the periods prior to the year
ended December 31, 2002 as the impact was not material.
56
The after-tax effect of the actual 2002 impact of these items
decreased net income for the year ended December 31, 2002, by $71 million, or
$0.24 per share.
The adjustments described above are anticipated to result in a
decrease in reported net income through 2005 and an increase in net income for
the period 2006 through 2017, the end of the lease term for Beaver Valley Unit
2.
After giving effect to the restatement, total transition cost
amortization (including above market leases) is expected to approximate the
following for the years from 2003 through 2009 (in millions).
2003 $685
2004 786
2005 913
2006 378
2007 213
2008 163
2009 44
DISCONTINUED OPERATIONS -
On April 18, 2003, FirstEnergy divested its ownership in Emdersa
through the abandonment of its shares in Emdersa's parent company, GPU Argentina
Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's
shares to the independent Board of Directors of GPU Argentina Holdings,
relieving FirstEnergy of all rights and obligations relative to this business.
As a result of the abandonment, FirstEnergy recorded a $67.4 million change in
the second quarter 2003.
As a result of FirstEnergy's divestiture of its ownership in Emdersa
in April 2003, FirstEnergy has reflected the results of this business during
2002 as a discontinued operation in the restated year ended December 31, 2002
Consolidated Statement of Income as "Discontinued Operations". There was no
impact on the year ended December 31, 2001 Consolidated Statement of Income as
Emdersa was reported as an asset held for sale during this period.
The following table summarizes Emdersa's major assets and
liabilities included in FirstEnergy's Consolidated Balance Sheet as of December
31, 2002. The amounts have not been reflected separately in the accompanying
balance sheets as the amounts are not significant to the Consolidated Balance
Sheet.
(in thousands)
--------------
Assets Abandoned:
Current assets $ 17,344
Property, plant and equipment 61,980
Other 8,737
--------
Total Assets $ 88,061
========
Liabilities Related to Assets Abandoned:
Current liabilities $ 12,777
Long-term debt 100,202
Other 10,548
--------
Total Liabilities $123,527
========
OTHER ADJUSTMENTS -
57
The Company has included in this restatement certain immaterial
adjustments that were not previously recognized in 2002 related to the
recognition of a valuation allowance on a tax benefit recognized in 2002 and
other adjustments. The impact of these adjustments decreased net income by $11.3
million
The effects of all of these adjustments on the Consolidated Statement
of Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows
previously reported, and revised per Note 3(L) above, for December 31, 2002 are
as follows:
TRANSITION ABOVE
AS PREVIOUSLY COST MARKET DISCONTINUED AS
REPORTED AMORTIZATION LEASES OPERATIONS OTHER RESTATED
-------- ------------ ------ ---------- ----- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
CONSOLIDATED STATEMENT OF INCOME
REVENUES:
Electric utilities $ 9,165,805 $ -- $ -- $ -- $ -- $ 9,165,805
Unregulated businesses 3,081,596 -- -- (16,875) -- 3,064,721
------------ ------------ ------------ ------------ ------------ ------------
Total revenues 12,247,401 -- -- (16,875) -- 12,230,526
------------ ------------ ------------ ------------ ------------ -------------
EXPENSES:
Fuel and purchased power 3,673,610 -- -- -- (10,700) 3,662,910
Purchased gas 592,116 -- -- -- -- 592,116
Other operating expenses 3,973,781 -- (90,688) (8,984) 14,800 3,888,909
Provision for depreciation and
amortization 1,105,904 150,474 50,272 (807) -- 1,305,843
General taxes 650,329 -- -- -- -- 650,329
------------ ------------ ------------ ------------ ------------ -------------
Total expenses 9,995,740 150,474 (40,416) (9,791) 4,100 10,100,107
------------ ------------ ------------ ------------ ------------ -------------
CUMULATIVE ADJUSTMENT FOR
RETAINED BUSINESSES PREVIOUSLY
HELD FOR SALE (NOTE 2L) (93,723) -- -- 93,723 -- --
------------ ------------ ------------ ------------ ------------ -------------
INCOME BEFORE INTEREST AND INCOME
TAXES 2,157,938 (150,474) 40,416 86,639 (4,100) 2,130,419
------------ ------------ ------------ ------------ ------------ ------------
NET INTEREST CHARGES:
Interest expense 911,109 -- -- (837) -- 910,272
Capitalized interest (24,474) -- -- -- -- (24,474)
Subsidiaries' preferred stock
dividends 78,947 -- -- -- (3,300) 75,647
------------ ------------ ------------ ------------ ------------ -------------
Net interest charges 965,582 -- -- (837) (3,300) 961,445
------------ ------------ ------------ ------------ ------------ -------------
INCOME TAXES 563,076 (30,920) (13,962) -- 10,500 528,694
------------ ------------ ------------ ------------ ------------ ------------
INCOME BEFORE DISCONTINUED
OPERATIONS 629,280 (119,554) 54,378 87,476 (11,300) 640,280
DISCONTINUED OPERATIONS -- -- -- (87,476) -- (87,476)
------------ ------------ ------------ ------------ ------------ -------------
NET INCOME $ 629,280 $ (119,554) $ 54,378 -- $ (11,300) $ 552,804
============ ============ ============ ============ ============ ============
BASIC EARNINGS PER SHARE OF
COMMON STOCK $ 2.15 $ (0.41) $ 0.19 -- $(0.04) $ 1.89
DILUTED EARNINGS PER SHARE OF
COMMON STOCK $ 2.14 $ (0.41) $ 0.19 -- $(0.04) $ 1.88
58
TRANSITION ABOVE
AS PREVIOUSLY COST MARKET AS
REPORTED AMORTIZATION LEASES OTHER RESTATED
-------- ------------ ----------- ----- --------
(IN THOUSANDS)
CONSOLIDATED BALANCE SHEET
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 196,301 $ -- $ -- $ -- $ 196,301
Receivables -
Customers 1,153,486 -- -- -- 1,153,486
Other 473,106 -- -- (3,500) 469,606
Materials and supplies, at average cost
Owned 253,047 -- -- -- 253,047
Under consignment 174,028 -- -- -- 174,028
Prepayments and other 203,630 -- -- -- 203,630
------------ ------------ ------------ ------------ ------------
2,453,598 -- -- (3,500) 2,450,098
------------ ------------ ------------ ------------ ------------
PROPERTY, PLANT AND EQUIPMENT:
In service 20,372,224 -- -- -- 20,372,224
Less--Accumulated provision for depreciation 8,551,427 -- -- 1,500 8,552,927
------------ ------------ ------------ ------------ ------------
11,820,797 -- -- (1,500) 11,819,297
Construction work in progress 859,016 -- -- 859,016
------------ ------------ ------------ ------------ ------------
12,679,813 -- -- (1,500) 12,678,313
------------ ------------ ------------ ------------ ------------
INVESTMENTS:
Capital trust investments (Note 4) 1,079,435 -- -- -- 1,079,435
Nuclear plant decommissioning trusts 1,049,560 -- -- -- 1,049,560
Letter of credit collateralization (Note 4) 277,763 -- -- -- 277,763
Other 918,874 -- -- -- 918,874
------------ ------------ ------------ ------------ ------------
3,325,632 -- 3,325,632
------------ ------------ ------------ ------------ ------------
DEFERRED CHARGES:
Regulatory assets 8,323,001 (154,600) 585,000 -- 8,753,401
Goodwill 5,896,292 -- 381,780 -- 6,278,072
Other (Note 2I) 902,437 -- -- (1,600) 900,837
------------ ------------ ------------ ------------ ------------
15,121,730 -- -- (1,600) 15,932,310
------------ ------------ ------------ ------------ ------------
$ 33,580,773 $ (154,600) $ 466,780 $ (6,600) $ 34,386,353
============ ============ ============ ============ ============
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and
preferred stock $ 1,702,822 $ -- $ -- $ -- $ 1,702,822
Short-term borrowings (Note 6) 1,092,817 -- -- -- 1,092,817
Accounts payable 918,268 -- -- (11,800) 906,468
Accrued taxes 456,178 -- -- (1,057) 455,121
Other 1,000,415 -- 84,600 8,800 1,093,815
------------ ------------ ------------ ------------ ------------
5,170,500 -- 84,600 (4,057) 5,251,043
------------ ------------ ------------ ------------ ------------
CAPITALIZATION
Common stockholders' equity(a) 7,120,049 (123,680) 58,504 (4,212) 7,050,661
Preferred stock of consolidated subsidiaries --
Not subject to mandatory redemption 335,123 -- -- -- 335,123
Subject to mandatory redemption 18,521 -- -- -- 18,521
Subsidiary-obligated mandatorily
redeemable preferred securities (Note 5F) 409,867 -- -- -- 409,867
Long-term debt 10,872,216 -- -- -- 10,872,216
------------ ------------ ------------ ------------ ------------
18,755,776 (123,680) 58,504 (4,212) 18,686,388
------------ ------------ ------------ ------------ ------------
DEFERRED CREDITS:
Accumulated deferred income taxes 2,367,997 (31,346) (282,324) 15,355 2,069,682
Accumulated deferred investment tax credits 235,758 426 -- -- 236,184
Nuclear plant decommissioning costs 1,254,344 -- -- (10,786) 1,243,558
Power purchase contract loss liability 3,136,538 -- -- -- 3,136,538
Retirement benefits 1,564,930 -- -- -- 1,564,930
Other 1,094,930 -- 1,106,000 (2,900) 2,198,030
------------ ------------ ------------ ------------ ------------
9,654,497 (30,920) 823,676 1,669 10,448,922
------------ ------------ ------------ ------------ ------------
COMMITMENTS, GUARANTEES AND CONTINGENCIES
$ 33,580,773 $ (154,600) $ 966,780 $ (6,600) $ 34,386,353
============ ============ ============ ============ ============
(a) Other adjustments include an impact to other comprehensive income.
60
TRANSITION
AS PREVIOUSLY COST LEASE DISCONTINUED AS
REPORTED AMORTIZATION OBLIGATIONS OPERATIONS OTHER RESTATED
----------- ----------- ----------- ----------- ----------- -----------
(IN THOUSANDS)
CONSOLIDATED STATEMENT OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 629,280 $ (119,554) $ 54,378 $ -- $ (11,300) $ 552,804
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and
amortization 1,105,904 150,474 50,272 (807) -- 1,305,843
Nuclear fuel and lease amortization 80,507 -- -- -- -- 80,507
Other amortization, net (Note 2) (16,593) -- -- -- -- (16,593)
Deferred costs recoverable as
regulatory assets (362,956) -- -- -- -- (362,956)
Avon investment impairment (Note 3) 50,000 -- -- -- -- 50,000
Deferred income taxes, net 89,860 (29,666) (13,962) -- 10,500 56,732
Investment tax credits, net (27,071) (1,254) -- -- -- (28,325)
Cumulative adjustment (see Note 2 (L)) 93,723 -- -- (93,723) -- --
Discontinued operations (see Note (M)) -- -- -- 87,476 -- 87,476
Receivables (85,307) -- -- -- -- (85,307)
Materials and supplies (29,557) -- -- -- -- (29,557)
Accounts payable 220,762 -- -- -- -- 220,762
Deferred lease costs -- -- (84,800) -- -- (84,800)
Other (Note 9) 166,735 -- (5,888) 7,054 800 168,701
----------- ----------- ----------- ----------- ----------- -----------
Net cash provided from operating
activities 1,915,287 -- -- -- -- 1,915,287
----------- ----------- ----------- ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net cash provided from (used for)
financing activities (1,123,469) -- -- -- -- (1,123,469)
----------- ----------- ----------- ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash provided from (used for)
investing activities (815,695) -- -- -- -- (815,695)
----------- ----------- ----------- ----------- ----------- -----------
Net increase (decrease) in cash and
cash equivalents (23,877) -- -- -- -- (23,877)
Cash and cash equivalents at
beginning of year 220,178 -- -- -- -- 220,178
----------- ----------- ----------- ----------- ----------- -----------
Cash and cash equivalents at end of year $ 196,301 $ -- $ -- -- $ -- $ 196,301
=========== =========== =========== =========== =========== ===========
3. DIVESTITURES:
INTERNATIONAL OPERATIONS-
FirstEnergy identified certain former GPU international operations
for divestiture within one year of the merger. These operations constitute
individual "lines of business" as defined in APB 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 were
not included in FirstEnergy's 2001 Consolidated Statements of Income.
Additionally, assets and liabilities of these international operations were
segregated under separate captions on the Consolidated Balance Sheet as of
December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets
Pending Sale."
Upon completion of its merger with GPU, FirstEnergy accepted an
October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase
Avon Energy Partners Holdings (Avon), FirstEnergy's wholly owned holding company
for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7
billion of debt). The transaction closed on May 8, 2002 and reflected the March
2002 modification of Aquila's initial offer such that Aquila acquired a 79.9
percent equity interest in Avon for approximately $1.9 billion (including the
assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155
million in cash and a note receivable for approximately $87 million
(representing the present value of $19 million per year to be received over six
years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy
and Aquila together own all of the outstanding shares of Avon through a jointly
owned subsidiary, with each company having an ownership voting interest.
Originally, in accordance with applicable accounting guidance, the earnings of
those foreign operations were not recognized in current earnings from the date
of the GPU acquisition. However, as a result of the decision to retain an
ownership interest in Avon in the quarter ended March 31, 2002, EITF Issue No.
90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating
to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the
purchase price of GPU based on amounts as of the purchase date as if Avon had
never been held for sale, including reversal of the effects of having applied
EITF Issue No. 87-11, to the transaction. The effect of reallocating the
purchase price and reversal of the effects of Issue No. 87-11, including the
allocation of capitalized interest, has been reflected in the Consolidated
Statement of Income for the year ended
61
December 31, 2002 by reclassifying certain revenue and expense amounts related
to activity during the quarter ended March 31, 2002 to their respective income
statement classifications. See Note 2(L) for the effects of the change in
classification. In the fourth quarter of 2002, FirstEnergy recorded a $50
million charge to reduce the carrying value of its remaining 20.1 percent
interest.
GPU's former Argentina operations were also identified by
FirstEnergy for divestiture within one year of the merger. FirstEnergy
determined the fair value of its Argentina operations, GPU Empresa Distribuidora
Electrica Regional S.A. and affiliates (Emdersa), 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 Emdersa's estimated fair value. These events
include currency devaluation, restrictions on repatriation of cash, and the
anticipation of future asset sales in that region by competitors. FirstEnergy
did not reach a definitive agreement to sell Emdersa as of December 31, 2002.
Therefore, these assets were no longer classified as "Assets Pending Sale" on
the Consolidated Balance Sheet as of December 31, 2002 and Emdersa's results of
operations were included in FirstEnergy's 2002 Consolidated Statement of Income.
Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth
quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment
for Retained Businesses Previously Held for Sale" on its 2002 Consolidated
Statement of Income related to Emdersa's cumulative results of operations from
November 7, 2001 through September 30, 2002. The amount of this one-time,
after-tax charge was $93.7 million, or $0.32 per share of common stock
(comprised of $108.9 million in currency transaction losses arising principally
from U.S. dollar denominated debt, offset by $15.2 million of operating income).
See Note 2(L) for the effects of the change in classification and Note 2(M) for
discontinued operations treatment.
On October 1, 2002, FirstEnergy began consolidating the results of
Emdersa's operations in its financial statements. In addition to the currency
transaction losses of $108.9 million, FirstEnergy recognized a currency
translation adjustment in other comprehensive income of $91.5 million as of
December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This
adjustment represents the impact of translating Emdersa's financial statements
from its functional currency to the U.S. dollar for GAAP financial reporting.
SALE OF GENERATING ASSETS-
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 MW to NRG Energy Inc. On August 8, 2002,
FirstEnergy notified NRG that it was canceling the agreement because NRG stated
that it could not complete the transaction under the original terms of the
agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to
pursue legal action against NRG, its affiliate and its parent, Xcel Energy, for
damages, based on the anticipatory breach of the agreement. On February 25,
2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's request for
arbitration against NRG.
In December 2002, FirstEnergy decided to retain ownership of these
plants after reviewing other bids it subsequently received from other parties
who had expressed interest in purchasing the plants. Since FirstEnergy did not
execute a sales agreement by year-end, it reflected approximately $74 million
($43 million net of tax) of previously unrecognized depreciation and other
transaction costs in the fourth quarter of 2002 related to these plants from
November 2001 through December 2002 on its Consolidated Statement of Income.
4. 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 any renewal term at a price equal to the fair market value of the
facilities. The basic rental payments are adjusted when applicable federal tax
law changes.
OES Finance, Incorporated, a wholly owned subsidiary of 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 of
approximately $278 million pledged to the financial institution providing those
letters of credit are the sole property of OES Finance and are investments which
are classified as "Held to Maturity". In the event of liquidation, OES Finance,
as a separate corporate entity, would have to satisfy its obligations to
creditors before any of its assets could be made available to OE as sole owner
of OES Finance common stock.
62
Consistent with the regulatory treatment, the rentals for capital
and operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 2002,
are summarized as follows:
2002 2001 2000
------- ------- -------
(IN MILLIONS)
Operating leases
Interest element $ 188.4 $ 194.1 $ 202.4
Other 135.9 120.5 111.1
Capital leases
Interest element 2.4 8.0 12.3
Other 2.5 35.5 64.2
------- ------- -------
Total rentals $ 329.2 $ 358.1 $ 390.0
======= ======= =======
The future minimum lease payments as of December 31, 2002, are:
OPERATING LEASES
------------------------------------
CAPITAL LEASE CAPITAL
LEASES PAYMENTS TRUSTS NET
-------- -------- -------- --------
(IN MILLIONS)
2003 $ 4.6 $ 331.9 $ 178.8 $ 153.1
2004 6.0 293.8 111.8 182.0
2005 5.4 313.4 130.3 183.1
2006 5.4 322.0 141.8 180.2
2007 1.8 299.5 130.7 168.8
Years thereafter 8.0 2,807.9 977.7 1,830.2
-------- -------- -------- --------
Total minimum lease payments 31.2 $4,368.5 $1,671.1 $2,697.4
======== ======== ========
Executory costs 7.1
--------
Net minimum lease payments 24.1
Interest portion 8.3
--------
Present value of net minimum
lease payments 15.8
Less current portion 1.8
--------
Noncurrent portion $ 14.0
--------
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.
5. 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-
An ESOP Trust funds most of the matching contribution for
FirstEnergy's 401(k) savings plan. 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
2002, 2001 and 2000, 1,151,106 shares, 834,657 shares and 826,873 shares,
respectively, were allocated to employees with the corresponding expense
recognized based on the shares allocated method. The fair value of 3,966,269
shares unallocated as of December 31, 2002, was approximately $130.8 million.
Total ESOP-related compensation expense was calculated as follows:
2002 2001 2000
(IN MILLIONS)
-----------------------------------------------------------------------------------------------------
Base compensation $34.2 $25.1 $18.7
Dividends on common stock held by the ESOP
and used to service debt (7.8) (6.1) (6.4)
-----------------------------------------------------------------------------------------------------
Net expense $26.4 $19.0 $12.3
=====================================================================================================
(C) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock-based plans administered by FirstEnergy include
the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
------------------------------------------------------------------------------------
Restricted common shares granted 36,922 133,162 208,400
Weighted average market price $36.04 $35.68 $26.63
Weighted average vesting period (years) 3.2 3.7 3.8
Dividends restricted Yes * Yes
------------------------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan
dividends are paid as unrestricted cash on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
See Note 9 - Other Information for discussion of stock-based
employee compensation expense recognized for restricted stock and EDCP stock
units.
64
Stock option activities under the FE Programs for the past three
years were as follows:
NUMBER OF WEIGHTED AVERAGE
STOCK OPTION ACTIVITIES OPTIONS EXERCISE PRICE
---------------------------------------------------------------------------------------
Balance, January 1, 2000 2,153,369 $25.32
(159,755 options exercisable) 24.87
Options granted 3,011,584 23.24
Options exercised 90,491 26.00
Options forfeited 52,600 22.20
Balance, December 31, 2000 5,021,862 24.09
(473,314 options exercisable) 24.11
Options granted 4,240,273 28.11
Options exercised 694,403 24.24
Options forfeited 120,044 28.07
Balance, December 31, 2001 8,447,688 26.04
(1,828,341 options exercisable) 24.83
Options granted 3,399,579 34.48
Options exercised 1,018,852 23.56
Options forfeited 392,929 28.19
Balance, December 31, 2002 10,435,486 28.95
(1,400,206 options exercisable) 26.07
As of December 31, 2002, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected
in net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 2G - Stock-Based Compensation.
(D) PREFERRED AND PREFERENCE STOCK-
Penn's 7.75% series has a restriction which prevents early
redemption prior to July 2003. All other preferred stock may be redeemed by the
Companies in whole, or in part, with 30-90 days' notice.
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 $ 7.35C 10,000 $ 100
Penn 7.625% 7,500 100
-----------------------------------------------------------------------------
Annual sinking fund requirements for the next five years are $1.8 million
in each year 2003 through 2006 and $12.3 million in 2007.
(F) SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED
DEBENTURES OF SUBSIDIARIES-
CEI formed a statutory business trust as a wholly owned financing
subsidiary. The trust sold preferred securities and invested the gross proceeds
in the 9.00% subordinated debentures of CEI and the sole assets of the trust are
the applicable subordinated debentures. Interest payment provisions of the
subordinated debentures match the distribution payment provisions of the trust's
preferred securities. In addition, upon redemption or payment at maturity of
subordinated debentures, the trust's preferred securities will be redeemed on a
pro rata basis at their liquidation value.
65
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. CEI has effectively provided a full
and unconditional guarantee of payments due on its trust's preferred securities.
Its trust preferred securities are redeemable at 100% of their principal amount
at CEI's option beginning in December 2006.
Met-Ed and Penelec each formed statutory business trusts for
substantially similar transactions as 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.
JCP&L 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 the limited partnership's MIPS. The limited
partnership's MIPS are redeemable at JCP&L's option at 100% of their principal
amount.
In each 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, 2002:
STATED SUBORDINATED
MATURITY RATE VALUE(A) DEBENTURES
- -----------------------------------------------------------------------------------------------------
(IN MILLIONS)
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
- -----------------------------------------------------------------------------------------------------
(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.
(G) LONG-TERM DEBT-
Each of the Companies has a first mortgage indenture under which it
issues from time to time first mortgage bonds secured by a direct first mortgage
lien on substantially all of its property and franchises, other than
specifically excepted property. FirstEnergy and its subsidiaries have various
debt covenants under their respective financing arrangements. The most
restrictive of the debt covenants relate to the nonpayment of interest and/or
principal on debt and the maintenance of certain financial ratios. The
nonpayments debt covenant which could trigger a default is applicable to
financing arrangements of FirstEnergy and all of the Companies. The maintenance
of minimum fixed charge ratios and debt to capitalization ratios covenants is
applicable to financing arrangements of FirstEnergy, the Ohio Companies and
Penn. There also exists cross-default provisions among financing arrangements of
FirstEnergy and the Companies.
Based on the amount of bonds authenticated by the respective
mortgage bond trustees through December 31, 2002, the Companies' annual
improvement fund requirements for all bonds issued under the various mortgage
indentures of the Companies amounts to $61.5 million. OE and Penn expect to
deposit funds with their respective mortgage bond trustees in 2003 that will
then be withdrawn upon the surrender for cancellation of a like principal amount
of bonds, specifically authenticated for such purposes against unfunded property
additions or against previously retired bonds. This method can result in minor
increases in the amount of the annual sinking fund requirement. 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 respective
mortgage bond trustees.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
66
(IN MILLIONS)
------------
2003 $1,698.8
2004 1,603.8
2005 918.5
2006 1,402.2
2007 251.9
-----------
Included in the table above are amounts for various variable
interest rate long-term debt which have provisions by which individual debt
holders have the option to "put back" or require the respective debt issuer to
redeem their debt at those times when the interest rate may change prior to its
maturity date. These amounts are $626 million, $266 million and $47 million in
2003, 2004 and 2005, respectively, which represents the next date at which the
debt holders may exercise this provision.
The Companies' obligations to repay certain pollution control
revenue bonds are secured by several series of first mortgage bonds. Certain
pollution control revenue bonds are entitled to the benefit of irrevocable bank
letters of credit of $287.6 million and noncancelable municipal bond insurance
policies of $544.1 million to pay principal of, or interest on, the pollution
control revenue bonds. To the extent that drawings are made under the letters of
credit or policies, the Companies are entitled to a credit against their
obligation to repay those bonds. The Companies pay annual fees of 1.00% 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 $395 million as of December
31, 2002, under its $500 million long-term revolving credit facility agreement
which expires November 29, 2004. FirstEnergy currently pays an annual facility
fee of 0.25% on the total credit facility amount. The fee is subject to change
based on changes to FirstEnergy's credit ratings.
CEI and TE have unsecured letters of credit of approximately $215.9
million in connection with the sale and leaseback of Beaver Valley Unit 2 that
expire in April 2005. CEI and TE are jointly and severally liable for the
letters of credit. In connection with its Beaver Valley Unit 2 sale and
leaseback arrangements, OE has similar letters of credit secured by deposits
held by its subsidiary, OES Finance (see Note 4).
(H) SECURITIZED TRANSITION BONDS-
On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly
owned limited liability company of JCP&L, sold $320 million of transition bonds
to securitize the recovery of JCP&L's bondable stranded costs associated with
the previously divested Oyster Creek Nuclear Generating Station.
JCP&L does not own nor did it purchase any of the transition bonds,
which are included in long-term debt on FirstEnergy's and JCP&L's Consolidated
Balance Sheets. The transition bonds represent obligations only of the Issuer
and are collateralized solely by the equity and assets of the Issuer, which
consist primarily of bondable transition property. The bondable transition
property is solely the property of the Issuer.
Bondable transition property represents the irrevocable right of a
utility company to charge, collect and receive from its customers, through a
non-bypassable transition bond charge, the principal amount and interest on the
transition bonds and other fees and expenses associated with their issuance.
JCP&L, as servicer, manages and administers the bondable transition property,
including the billing, collection and remittance of the transition bond charge,
pursuant to a servicing agreement with the Issuer. JCP&L is entitled to a
quarterly servicing fee of $100,000 that is payable from transition bond charge
collections.
(I) 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, 2002, accumulated other comprehensive income (loss) consisted of a
minimum liability for unfunded retirement benefits of $450.2 million, unrealized
losses on investments in securities available for sale of $4.3 million,
unrealized losses on derivative instrument hedges of $110.2 million and
unrealized currency translation adjustments of $91.4 million. See Note 9 - Other
Information for discussion of derivative instruments reclassifications to net
income.
(J) STOCK REPURCHASE PROGRAM-
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 and
2000, FirstEnergy repurchased and retired 550,000 shares (average price of
$27.82 per share), and 7.9 million shares (average price of $24.51 per share),
respectively.
67
6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding as of December 31, 2002,
consisted of $933.1 million of bank borrowings and $159.7 million of OES
Capital, Incorporated commercial paper. OES Capital is a wholly owned subsidiary
of OE whose borrowings are secured by customer accounts receivable. OES Capital
can borrow up to $170 million under a receivables financing agreement at rates
based on certain bank commercial paper and is required to pay an annual fee of
0.20% on the amount of the entire finance limit. The receivables financing
agreement expires in August 2003.
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 $1.084 billion
under various interest rate options. 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 2003. The
weighted average interest rates on short-term borrowings outstanding as of
December 31, 2002 and 2001, were 2.41% and 3.80%, respectively.
7. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
FirstEnergy's current forecast reflects expenditures of
approximately $3.1 billion for property additions and improvements from
2003-2007, of which approximately $727 million is applicable to 2003.
Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $485 million, of which approximately $69 million
applies to 2003. During the same periods, the Companies' nuclear fuel
investments are expected to be reduced by approximately $483 million and $88
million, respectively, as the nuclear fuel is consumed.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
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 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 $68.4 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, repair and replacement costs and other
such costs arising from a nuclear incident at any of the Companies' plants
exceed the policy limits of the insurance in effect with respect to that plant,
to the extent a nuclear incident is determined not to be covered by the
Companies' insurance policies, or to the extent such insurance becomes
unavailable in the future, the Companies would remain at risk for such costs.
(C) GUARANTEES AND OTHER ASSURANCES-
As part of normal business activities, FirstEnergy enters into
various agreements on behalf of its subsidiaries to provide financial or
performance assurances to third parties. Such agreements include contract
guarantees, surety bonds and rating-contingent collateralization provisions. As
of December 31, 2002, outstanding guarantees and other assurances aggregated
$913 million.
FirstEnergy guarantees energy and energy-related payments of its
subsidiaries involved in energy marketing activities - principally to facilitate
normal physical transactions involving electricity, gas, emission allowances and
coal. FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy and its subsidiaries to fulfill
the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financing where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables
the counterparty's legal claim to be satisfied by other FirstEnergy assets. The
likelihood that such parental guarantees of $856 million as of December 31, 2002
will increase amounts otherwise to be paid by FirstEnergy to meet its
obligations incurred in connection with financings and ongoing energy and
energy-related contracts is remote.
68
Most of FirstEnergy's surety bonds are backed by various
indemnities common within the insurance industry. Surety bonds and related
FirstEnergy guarantees of $26 million provide additional assurance to outside
parties that contractual and statutory obligations will be met in a number of
areas including construction jobs, environmental commitments and various retail
transactions.
Various energy supply contracts contain credit enhancement
provisions in the form of cash collateral or letters of credit in the event of a
reduction in credit rating below investment grade. These provisions vary and
typically require more than one rating reduction to fall below investment grade
by Standard & Poor's or Moody's Investors Service to trigger additional
collateralization by FirstEnergy. As of December 31, 2002, rating-contingent
collateralization totaled $31 million.
(D) 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 $159 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2003 through 2007.
The Companies are required to meet federally approved sulfur
dioxide (SO2) regulations. Violations of such regulations can result in shutdown
of the generating unit involved and/or civil or criminal penalties of up to
$31,500 for each day the unit is in violation. The Environmental Protection
Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that
allows for compliance based on a 30-day averaging period. The Companies cannot
predict what action the EPA may take in the future with respect to the interim
enforcement policy.
The Companies believe they are in compliance with the current SO2
and nitrogen 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 SIP that requires compliance with
the NOx budgets at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient
Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit 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, for which hearings began on February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act based on operation and maintenance of the Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. Although unable to predict the
outcome of these proceedings, 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
69
coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced
that it will develop national standards regulating disposal of coal ash under
its authority to regulate nonhazardous waste.
The 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; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, 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. 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 its SBC. The Companies have total accrued liabilities aggregating
approximately $54.3 million as of December 31, 2002.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on FirstEnergy's
earnings and competitive position. These environmental regulations affect
FirstEnergy's earnings and competitive position to the extent it competes with
companies that are not subject to such regulations and therefore do not bear the
risk of costs associated with compliance, or failure to comply, with such
regulations. FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict whether environmental regulations will
change and what, if any, the effects of such change would be.
(E) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims for personal injury, asbestos and property
damage and proceedings related to FirstEnergy's normal business operations are
pending against FirstEnergy and its subsidiaries. The most significant are
described below.
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 had been 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. On January
15, 2002, the District Court granted GPU's July 2001 motion for summary judgment
on the remaining 2,100 pending claims. On February 14, 2002, plaintiffs filed a
notice of appeal to the United States Court of Appeals for the Third Circuit. In
December 2002, the Court of Appeals refused to hear the appeal which effectively
ended further legal action for those claims.
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 JCP&L's territory. 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. 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
judgment that is currently pending before the Superior Court. FirstEnergy is
unable to predict the outcome of these matters.
(F) OTHER COMMITMENTS AND CONTINGENCIES-
GPU made significant investments in foreign businesses and
facilities through its GPU Capital 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.
EI Barranquilla, a wholly owned subsidiary of GPU Power, is a
28.67% equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos
(TEBSA), which owns a Colombian independent power generation project. GPU Power
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 $254 million as of December 31,
2002. The lenders include the Overseas Private Investment Corporation, US Export
Import Bank and a commercial bank syndicate. FirstEnergy has guaranteed the
obligations of the operators of the TEBSA project, up to a maximum of $5.9
million (subject to escalation) under the project's operations and maintenance
agreement.
70
8. SEGMENT INFORMATION:
FirstEnergy operates under two reportable segments: regulated
services and competitive services. The aggregate "Other" segments do not
individually meet the criteria to be considered a reportable segment. "Other"
consists of interest expense related to the 2001 merger acquisition debt; the
corporate support services operating segment and the international businesses
acquired in the 2001 merger. The international business assets reflected in the
2001 "Other" assets amount included assets in the United Kingdom identified for
divestiture (see Note 3 - Divestitures) which were sold in 2002. As those assets
were in the process of being sold, their performance was not being reviewed by a
chief operating decision maker and in accordance with SFAS 131, "Disclosures
about Segments of an Enterprise and Related Information," did not qualify as an
operating segment. The remaining assets and revenues for the corporate support
services and the remaining international businesses were below the quantifiable
threshold for operating segments for separate disclosure as "reportable
segments." FirstEnergy's primary segment is its regulated services segment,
which includes eight electric utility operating companies in Ohio, Pennsylvania
and New Jersey that provide electric transmission and distribution services. 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 a competing 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.
Segment financial data in 2001 and 2000 have been reclassified to
conform with the current year business segment organizations and operations.
Changes in the current year methodology for computing revenues and expenses used
in management reporting for the Competitive Services segment have been reflected
in reclassified 2001 and 2000 financial results. Methodology changes included
using a fixed rate revenues calculation for the Competitive Services segment's
power sales agreement with the Regulated Services segment. This change, when
applied to previously reported results, caused lower revenues, income taxes and
net income as compared to prior calculated amounts and, correspondingly, reduced
purchased power expenses and increased income taxes and net income for the
Regulated Services segment. Financial data for these business segments are as
follows:
71
SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING
SERVICES SERVICES OTHER(C) ADJUSTMENTS CONSOLIDATED (C)
-------- -------- -------- ----------- ----------------
(IN MILLIONS)
2002
External revenues $ 8,794 $3,015 $409 $ 13 (a) $ 12,231
Internal revenues 1,052 1,666 478 (3,196) (b) --
Total revenues 9,846 4,681 887 (3,183) 12,231
Depreciation and amortization 1,235 30 41 -- 1,306
Net interest charges 587 46 386 (58) (b) 961
Income taxes 698 (87) (82) -- 529
Income before discontinued operations 938 (119) (179) -- 640
Discontinued operations -- -- (87) -- (87)
Net income 927 (108) (266) -- 553
Total assets 30,494 2,281 1,611 -- 34,386
Total goodwill 5,993 285 -- -- 6,278
Property additions 490 403 105 -- 998
2001
External revenues $ 5,729 $2,165 $ 11 $ 94 (a) $ 7,999
Internal revenues 1,645 1,846 350 (3,841) (b) --
Total revenues 7,374 4,011 361 (3,747) 7,999
Depreciation and amortization 841 21 28 -- 890
Net interest charges 571 25 74 (114) (b) 556
Income taxes 537 (23) (40) -- 474
Income before cumulative effect of a
change in accounting 729 (23) (51) -- 655
Net income 729 (32) (51) -- 646
Total assets 28,054 2,981 6,317 -- 37,352
Total goodwill 5,325 276 -- -- 5,601
Property additions 447 375 30 -- 852
2000
External revenues $ 5,415 $1,545 $ 1 $ 68 (a) $ 7,029
Internal revenues 1,222 2,114 306 (3,642) (b) --
Total revenues 6,637 3,659 307 (3,574) 7,029
Depreciation and amortization 919 13 2 -- 934
Net interest charges 558 10 19 (58) (b) 529
Income taxes 365 27 (15) -- 377
Net income 563 39 (3) -- 599
Total assets 14,682 2,685 574 -- 17,941
Total goodwill 1,867 222 -- -- 2,089
Property additions 422 126 40 -- 588
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.
(c) Restated - See Notes 2L and 2M.
PRODUCTS AND SERVICES
ENERGY RELATED
ELECTRICITY OIL & GAS SALES AND
YEAR SALES SALES SERVICES
---- ----- ----- --------
(IN MILLIONS)
2002 $9,697 $620 $1,052
2001 6,078 792 693
2000 5,537 582 563
2002 2001
-------------------------------- -------------------------------
GEOGRAPHIC INFORMATION REVENUES ASSETS REVENUES ASSETS
---------------------- -------- ------ -------- ------
(IN MILLIONS)
United States $11,908 $33,628 $7,991 $32,187
Foreign countries* 339 758 8 5,165
---------- ---------- ---------- --------
Total $12,247 $34,386 $7,999 $37,352
========== ========== ========== ========
* See Note 3 for discussion of future divestitures of international
operations and Note 2L for discussion of revised financial data.
72
9. OTHER INFORMATION:
The following financial data provides supplemental unaudited
information to the consolidated financial statements and notes previously
reported in 2001 and 2000:
(A) CONSOLIDATED STATEMENTS OF CASH FLOWS
2002 2001 2000
---- ---- ----
RESTATED (IN THOUSANDS)
Other Cash Flows From Operating Activities:
Accrued taxes $ 36,566 $ 8,915 $ (84)
Accrued interest (26,281) 117,520 (8,853)
Retail rate refund obligation payments (43,016) -- --
Interest rate hedge -- (132,376) --
Prepayments and other 132,980 (146,741) (21,975)
All other 68,452 (97,882) 76,441
--------- --------- ---------
Total-Other $ 168,701 $(250,564) $ 45,529
========= ========= =========
Other Cash Flows from Investing Activities:
Retirements and transfers $ 29,619 $ 40,106 $ (11,721)
Nonutility generation trusts investments 49,044 -- --
Nuclear decommissioning trust investments (86,221) (73,381) (30,704)
Aquila notes receivable (91,335) -- --
Other comprehensive income 8,745 (49,653) --
Other investments (16,689) (116,285) (25,481)
All other 52,482 (34,313) (52,289)
--------- --------- ---------
Total-Other $ (54,355) $(233,526) $(120,195)
========= ========= =========
(B) CONSOLIDATED STATEMENTS OF TAXES
2002 2001 2000
---- ---- ----
RESTATED (IN THOUSANDS)
Other Accumulated Deferred Income
Taxes at December 31:
Retirement Benefits $(381,285) $(133,282) $ (60,491)
Oyster Creek securitization (Note 5H) 202,447 -- --
Purchase accounting basis differences (2,657) (147,450) --
Sale of generating assets (11,786) 207,787 --
Provision for rate refund (29,370) (46,942) --
All other (193,497) (203,809) 22,767
--------- --------- ---------
Total-Other $(397,506) $(323,696) $ (37,724)
========= ========= =========
(C) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS
FirstEnergy's regulated and competitive subsidiaries record
purchase and sales transactions with PJM Interconnection ISO, an independent
system operator, on a gross basis in accordance with EITF Issue No. 99-19,
"Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate
purchase and sales transactions for the three years ended December 31, 2002, are
summarized as follows:
2002 2001 2000
------------------------------------------------------------------------------
(MILLIONS)
Sales $453 $142 $315
Purchases 687 204 271
------------------------------------------------------------------------------
FirstEnergy's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from the PJM ISO from power sales
(as reflected in the table above) during periods when FirstEnergy had additional
available power capacity. Revenues also include sales by FirstEnergy of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when FirstEnergy required additional power to meet its retail load
requirements and, secondarily, to make sales to the wholesale market.
73
(D) STOCK BASED COMPENSATION
Stock-based employee compensation expense recognized for the FE
Programs' restricted stock during 2002, 2001 and 2000 totaled $2,259,000,
$1,342,000 and $1,104,000, respectively. In addition, stock-based employee
compensation expense of $206,000, $1,637,000 and $1,646,000 during 2002, 2001
and 2000, respectively, was recognized for EDCP stock units (see Note 5C - Stock
Compensation Plans for further disclosure).
(E) SFAS 115 ACTIVITY
All other investments included under Investments other than cash
and cash equivalents in the table in Note 2J - Supplemental Cash Flows
Information include available-for-sale securities, at fair value, with the
following results:
2002 2001 2000
------ ------ ------
(IN THOUSANDS)
Unrealized holding gains $ 202 $2,236 $ 992
Unrealized holding losses 4,991 432 70
Proceeds from sales 7,875 25 66
Gross realized gains 31 -- 46
Gross realized losses -- 3 --
------ ------ ------
(F) DERIVATIVE INSTRUMENTS RECLASSIFICATIONS TO NET 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 (see
Note 5I - Comprehensive Income for further disclosure). Other comprehensive
income (loss) reclassified to net income in 2002 and 2001 totaled $(9.9) million
and $30.7 million, respectively. These amounts were net of income taxes in 2002
and 2001 of $(6.8) million and $21.7 million, respectively. There were no
reclassifications to net income in 2000.
10. OTHER RECENTLY ISSUED ACCOUNTING STANDARDS
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an interpretation of FASB
Statements No. 5, 57, and 107 and rescission of FASB Interpretation
No. 34"
The FASB issued FIN 45 in January 2003. This interpretation
identifies minimum guarantee disclosures required for annual periods ending
after December 15, 2002. It also clarifies that providers of guarantees must
record the fair value of those guarantees at their inception. This accounting
guidance is applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. FirstEnergy does not believe that implementation of FIN
45 will be material but it will continue to evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (FirstEnergy's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements, the sale of preferred securities and debt
secured by bondable property, which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46.
FirstEnergy currently consolidates the majority of these entities
and believes it will continue to consolidate following the adoption of FIN 46.
In addition to the entities FirstEnergy is currently consolidating FirstEnergy
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $11.6 million.
74
11. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by quarter for
2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002 (C)(D) JUNE 30, 2002 (D) SEPTEMBER 30, 2002 (D) DECEMBER 31, 2002
-------------------------------------------------------------------------------------------------------------------------
AS AS AS
PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
--------- --------- --------- --------- --------- --------- --------- ---------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues (a) $ 2,853.3 $ 2,853.3 $ 2,898.5 $ 2,898.5 $ 3,451.2 $ 3,451.2 $ 3,044.4 $ 3,027.5
Expenses (a) 2,363.6 2,362.3 2,230.4 2,272.7 2,681.7 2,724.0 2,746.8 2,741.1
Cumulative adjustment -- -- -- -- -- -- (93.7) --
--------- --------- --------- --------- --------- --------- --------- ---------
Income Before Interest and
Income Taxes 489.7 491 668.1 625.8 769.5 727.2 203.9 286.4
Net Interest Charges 278.7 278.7 250.3 250.3 220.4 220.4 216.2 212.0
Income Taxes 94.4 93.9 184.6 167.7 238.9 221.9 34.6 45.1
--------- --------- --------- --------- --------- --------- --------- ---------
Income Before Discontinued
Operations 116.6 118.4 233.2 207.8 310.3 284.8 (46.9) 29.3
Discontinued Operations -- -- -- -- -- -- -- (87.5)
--------- --------- --------- --------- --------- --------- --------- ---------
Net Income (Loss) $ 116.6 $ 118.4 $ 233.2 $ 207.8 $ 310.3 $ 284.8 $ (46.9) $ 58.2
========= ========= ========= ========= ========= ========= ========= =========
Basic Earnings (Loss) Per
Share of Common Stock $ .36 $ 0.41 $ .74 $ 0.71 $ .99 $ 0.97 $ (.16) $ (.20)
Diluted Earnings (Loss) Per
Share of Common Stock $ .36 $ 0.40 $ .73 $ 0.71 $ .98 $ 0.97 $ (.16) $ (.20)
========= ========= ========= ========= ========= ========= ========= =========
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
THREE MONTHS ENDED 2001 2001 2001 2001(B)
- ---------------------------------------------- --------- --------- --------- ---------
(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 2J) (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 2J) (.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 2J) (.04) -- -- --
--------- --------- --------- ---------
Diluted Earnings Per Share of Common Stock $ .45 $ .67 $ 1.06 $ .64
========= ========= ========= =========
(a) 2002 revenues and expenses related to trading activities reflect
reclassifications as a result of implementing EITF Issue No. 02-03 (see
Note 2C - Revenues).
(b) Results for the former GPU companies are included from the November 7,
2001 acquisition date through December 31, 2001.
(c) See Note 2L for discussion of revised financial data.
(d) See Note 2(M) for discussion of Restated financial data. Related to impact
of transition plan amortization and above works leases.
(e) Includes the impact of above makes totaling $11.3 million, principally
related to the recognition of a valuation allowance on a tax benefit
previously recognized in the fourth quarter of 2002.
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 they
exchanged. The cash portion of the merger consideration was approximately $2.2
billion and nearly 73.7 million shares of FirstEnergy common stock were issued
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
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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 700 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 combination of FirstEnergy and GPU was a key strategic step in
FirstEnergy achieving its vision of being the leading energy and related
services provider in the region. The merger combined companies with the
management, employee experience and technical expertise, retail customer base,
energy and related services platform and financial resources to grow and succeed
in a rapidly changing energy marketplace. The merger also allowed for a natural
alliance of companies with adjoining service areas and interconnected
transmission systems to eliminate duplicative costs, maximize efficiencies and
increase management and operational flexibility in order to enhance operations
and become a more effective competitor.
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. The following table summarizes the
estimated fair values of the assets acquired and liabilities assumed on the date
of acquisition.
(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
--------
During 2002, certain pre-acquisition contingencies and other final
adjustments to the fair values of the assets acquired and liabilities assumed
were reflected in the final allocation of the purchase price. These adjustments
primarily related to: (1) final actuarial calculations related to pension and
postretirement benefit obligations; (2) updated valuations of GPU's
international operations as of the date of the merger; (3) establishment of a
reserve for deferred energy costs recognized prior to the merger; and (4) return
to accrual adjustments for income taxes. As a result of these adjustments,
goodwill increased by approximately $290 million, which is attributable to the
regulated services segment.
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. The pro forma combined
condensed financial statements have been prepared to reflect the merger under
the purchase method of accounting with FirstEnergy acquiring GPU. 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
------- -------
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13. SUBSEQUENT EVENTS (UNAUDITED)
ENVIRONMENTAL MATTERS-
On August 8, 2003, FirstEnergy, OE and Penn reported a development
regarding a complaint filed by the U.S. Department of Justice with respect to
the W.H. Sammis Plant (see Note 7(D) Commitments, Guarantees and Contingencies -
Environmental Matters). As reported, on August 7, 2003, the United States
District Court for the Southern District of Ohio ruled that 11 projects
undertaken at the Sammis Plant between 1984 and 1998 required pre-construction
permits under the Clean Air Act. The ruling concludes the liability phase of the
case, which deals with applicability of Prevention of Significant Deterioration
provisions of the Clean Air Act. The remedy phase, which is currently scheduled
to be ready for trial beginning March 15, 2004, will address civil penalties and
what, if any, actions should be taken to further reduce emissions at the plant.
In the ruling, the Court indicated that the remedies it "may consider and impose
involved a much broader, equitable analysis, requiring the Court to consider air
quality, public health, economic impact, and employment consequences. The Court
may also consider the less than consistent efforts of the EPA to apply and
further enforce the Clean Air Act." The potential penalties that may be imposed,
as well as the capital expenditures necessary to comply with substantive
remedial measures that may be required, may have a material adverse impact on
the Company's financial condition and results of operations. Management is
unable to predict the ultimate outcome of this matter.
REGULATORY MATTERS-
New Jersey
On July 25, 2003, FirstEnergy and JCP&L announced that review is
underway concerning a decision by the NJBPU on JCP&L's rate proceeding (See Note
2(D)). Based on that review, JCP&L will decide its appropriate course of action,
which could include filing a request for reconsideration with the NJBPU and
possibly an appeal to the Appellate Division of the Superior Court of New
Jersey.
In its ruling, the NJBPU reduced JCP&L's annual revenues by
approximately $62 million, for an average rate decrease of 3 percent, effective
August 1, 2003. The NJBPU decision also provided for an interim return on equity
of 9.5 percent on JCP&L's rate base for the next 6 to 12 months. During that
period, JCP&L would initiate another proceeding to request recovery of
additional expenses incurred to enhance system reliability. In that proceeding,
the NJBPU could increase the return on equity to 9.75 percent or decrease it to
9.25 percent, depending on its assessment of the reliability of JCP&L's service.
Any reduction could be retroactive to August 1, 2003.
The NJBPU decision reflects elimination of $111 million in annual
customer credits mandated by the New Jersey Electric Discount and Energy
Competition Act (EDECA); a $223 million reduction in the energy delivery charge;
a net $1 million increase in the SBC; and a $49 million increase in the MTC. The
$1 million net SBC increase reflects approximately a $22 million increase
related to universal services' costs previously approved in a separate
proceeding, as well as reductions in other components of the SBC.
The MTC would allow for the recovery of $465 million of deferred
energy costs over the next 10 years on an interim basis, thus disallowing $153
million of the $618 million provided for in the settlement agreement. This
decision reflects the NJBPU's belief that a hindsight review comparing JCP&L's
power purchases to spot market prices provides the appropriate benchmark for
recovery. JCP&L's deferred energy costs primarily reflect mandated purchase
power contracts with NUG's that are above wholesale market prices, and costs of
providing basic generation service to customers in excess of the company's
capped basic generation service charges during the transition period under
EDECA, which ends August 1, 2003. At that time, the generation portion of most
customer bills will increase by an average of 7.5 percent as a result of the
outcome of the basic generation service auction conducted earlier this year by
the BPU.
In the second quarter of 2003, JCP&L recorded charges to net income
aggregating $158 million ($94 million net of tax) consisting of the $153 million
deferred energy costs and other regulatory assets.
On July 25, 2003, the NJBPU approved a Stipulation of Settlement
between the parties and authorized the recovery of the total $135 million of the
Freehold buyout costs, eliminating the interim nature of the recovery.
Pennsylvania
On April 2, 2003, the PPUC remanded the merger savings issue to the
Office of Administrative Judge ("ALJ") and directed Met-Ed and Penelec submit a
position paper by May 2, 2003 on the status of the Settlement Stipulation in
light of the Commonwealth Court's decision ("Court Order"). In summary, the
Met-Ed and Penelec submitted to the PPUC the following position:
- On January 16, 2003, the Pennsylvania Supreme Court denied or
quashed all appeals arising from the Court Order, thus rendering
the Court Order final.
77
- Because the parties sought to stay the PPUC's June 20, 2001 order
in which the Settlement Stipulation was approved, all terms and
conditions included therein that were not inconsistent with the
Court Order remained in effect.
- Only those provisions related to POLR cost recovery and POLR
deferral, issues addressed by the PPUC and expressly rejected by
the Commonwealth Court, must be removed from the Settlement
Stipulation.
- The GENCO Code of Conduct must be reinstated consistent with the
Court Order.
- All other provisions included in the Stipulation unrelated to these
three issues remain in effect.
On or about June 2, 2003, parties filed comments in response to the
position presented by Met-Ed and Penelec. The other parties' responses included
significant disagreement with the position paper and disagreement among the
other parties themselves, including the Stipulation's original signatory
parties. Some parties believe that no portion of the Stipulation has survived
the Commonwealth Court's Order. Based upon these comments, it became clear that
many of the parties not only disagreed with Met-Ed and Penelec, but also
disagreed among themselves. Partially because of this lack of consensus among
the parties, Met-Ed and Penelec submitted a letter on June 11, 2003, to the ALJ
informing the ALJ and all other parties that Met-Ed and Penelec were voiding the
Settlement Stipulation, pursuant to the termination provisions found therein.
Notwithstanding the voiding of the Settlement Stipulation, Met-Ed and Penelec
voluntarily agreed to retain virtually all of the customer benefits provided by
the Settlement Stipulation, including, among others, funding for renewable
energy resource and demand response programs. Met-Ed and Penelec also agreed to
cap distribution rates at current levels through 2007, provided that the PPUC
finds during the remanded merger saving proceedings that Met-Ed and Penelec have
satisfied the public interest test applicable to mergers and leave the
quantification of merger savings for a subsequent rate proceedings. They believe
this will significantly simplify the issues in the pending action by reinstating
Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC.
In addition, they have agreed to voluntarily continue certain Stipulation
provisions including funding for energy and demand side response programs and to
cap distribution rates at current levels through 2007. This voluntary
distribution rate cap is contingent upon a finding that Met-Ed and Penelec have
satisfied the "public interest" test applicable to mergers and that any rate
impacts of merger savings will be dealt with in a subsequent rate case. Met-Ed
and Penelec believe that their actions in voiding the Settlement Stipulation
will simplify the issues and limit them to the treatment of merger savings and
whether Met-Ed's and Penelec's accounting is consistent with the Court Order.
INTERNATIONAL OPERATIONS-
Pending Sale of Remaining Investment in Avon and Sale of Note from
Aquila
On May 22, 2003, FirstEnergy announced it reached an agreement to
sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that
agreement also includes Aquila's 79.9 percent interest (See Note 3). Under terms
of the agreement, Scottish and Southern will pay FirstEnergy and Aquila an
aggregate $70 million (FirstEnergy's share would be approximately $14 million).
Avon's debt will remain with that company. FirstEnergy also recognized in the
second quarter of 2003 an impairment of $12.6 million ($8.2 million after tax)
related to the carrying value of the note receivable from from the initial sale
of a 79.9 percent interest in Avon that occurred in May 2002. After receiving
the first annual installment payment of $19 million in May 2003, FirstEnergy
sold the remaining balance of the note in the secondary market and received
$63.2 million in proceeds on July 28, 2003.
Emdersa
On April 18, 2003, FirstEnergy divested its ownership in Emdersa
through the abandonment of its shares in Emdersa's parent company, GPU Argentina
Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's
shares to the independent Board of Directors of GPU Argentina Holdings,
relieving FirstEnergy of all rights and obligations relative to this business.
As a result of the abandonment, FirstEnergy recognized a one-time, non-cash
charge of $67.4 million, or $0.23 per share of common stock in the second
quarter of 2003. This charge is the result of realizing the CTA losses through
current period earnings ($89.8 million, or $0.30 per share), partially offset by
the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22.4
million, or $0.07 per share). Since FirstEnergy had previously recorded $90
million of CTA adjustments in OCI, the net effect of the $67.4 million charge
was an increase in common stockholders' equity of $22.4 million.
The $67.4 million charge does not include the anticipated income
tax benefits related to the abandonment, which were fully reserved during the
second quarter. FirstEnergy anticipates tax benefits of approximately $129
million, of which $50 million would increase net income in the period that it
becomes probable those benefits will be realized. The remaining $79 million of
tax benefits would reduce goodwill recognized in connection with the acquisition
of GPU.
78
OTHER MATTERS-
It is FirstEnergy's understanding that, as of August 18, 2003, five
individual described herein shareholder-plaintiffs have filed separate
complaints against FirstEnergy Corp. alleging various securities law violations
in connection with the restatement of earnings period. Most of these complaints
have not yet been officially served on the Company. Moreover, FirstEnergy is
still reviewing the suits that have been served in preparation for a responsive
pleading. FirstEnergy is , however, aware that in each case, the plaintiffs are
seeking certification from the court to represent a class of similarly situated
shareholders.
On August 14, 2003, eight states and southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. The cause of the outage has not been
determined. Having restored service to its customers, FirstEnergy is now in the
process of accumulating data and evaluating the status of its electrical system
prior to and during the outage event and would expect that the same effort Is
under way at utilities and regional transmission operators across the region.
As of August 18, 2003, the following facts about FirstEnergy's
system were known. Early in the afternoon of August 14, hours before the event,
Unit 5 of the Eastlake Plant in Eastlake, Ohio tripped off. Later in the
afternoon, three FirstEnergy transmission lines and one owned by American
Electric Power and FirstEnergy tripped out of service. The Midwest Independent
System Operator (MISO), which oversees the regional transmission grid, indicated
that there were a number of other transmission line trips in the region outside
of FirstEnergy's system. FirstEnergy customers experienced no service
interruptions resulting from these conditions. Indications to FirstEnergy were
that Company's system was stable. Therefore, no isolation of FirstEnergy's
system was called for. In addition, FirstEnergy determined that its computerized
system for monitoring and controlling its transmission and generation system was
operating, but the alarm screen function was not. However, MISO's monitoring
system was operating properly. It is clear that extensive data needs to be
gathered and analyzed in order to determine with any degree of certainty the
circumstances that led to the outage. This is a very complex situation, far
broader than the power line outages FirstEnergy experienced on its system. From
the preliminary data that has been gathered., it is clear that the transmission
grid in the Eastern Interconnection, not just within FirstEnergy's system, was
experiencing unusual electrical conditions at various times prior to the event.
These included unusual voltage and frequency fluctuations and load swings on the
grid. FirstEnergy is committed to working with the North American Electric
Reliability Council and others involved to determine exactly what events in the
entire affected region led to the outage. There is no timetable as to when this
entire process will be completed. It is, however, expected to last several
weeks, at a minimum.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED-
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 is effective for financial
instruments entered into or modified after May 31, 2003 and is effective at the
beginning of the first interim period beginning after June 15, 2003
(FirstEnergy's third quarter of 2003) for all other financial instruments.
FirstEnergy did not enter into or modify any financial instruments
within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150,
effective July 1, 2003, FirstEnergy expects to classify as debt the preferred
stock of consolidated subsidiaries subject to mandatory redemptions with a
carrying value of approximately $19 million as of June 30, 2003. Subsidiary
preferred dividends on FirstEnergy's Consolidated Statements of Income are
currently included in net interest charges. Therefore, the application of SFAS
150 will not require the reclassification of such preferred dividends to net
interest charges.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph
10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003 which would correspond to
FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue
C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify
for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides
guidance regarding when the presence in a contract of a general index, such as
the Consumer Price Index, would prevent that contract from qualifying for the
normal purchases and normal sales (NPNS) exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts. DIG
Issue C20 is to be applied prospectively to all existing contracts as of its
effective date and for all future transactions. If it is determined under DIG
Issue C20 guidance that the NPNS exception was claimed for an existing contract
that was not eligible for this exception, the contract will be recorded at fair
value, with a corresponding adjustment of net income as the cumulative effect of
a change in accounting principle in the fourth quarter of 2003. FirstEnergy is
currently assessing the new guidance and has not yet determined the impact on
its financial statements.
79
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when
arrangements contain a lease. Based on the EITF consensus, an arrangement
contains a lease if (1) it identifies specific property, plant or equipment
(explicitly or implicitly), and (2) the arrangement transfers the right to the
purchaser to control the use of the property, plant or equipment. The consensus
will be applied prospectively to arrangements committed to, modified or acquired
through a business combination, beginning in the third quarter of 2003.
FirstEnergy is currently assessing the new EITF consensus and has not yet
determined the impact on its financial position or results of operations
following adoption.
80