FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
- ----------- ------------------------------------- ------------------
333-21011 FIRSTENERGY CORP. 34-1843785
(An Ohio Corporation)
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-2578 OHIO EDISON COMPANY 34-0437786
(An Ohio Corporation)
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-3583 THE TOLEDO EDISON COMPANY 34-4375005
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-3491 PENNSYLVANIA POWER COMPANY 25-0718810
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY 21-0485010
(A New Jersey Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-446 METROPOLITAN EDISON COMPANY 23-0870160
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
1-3522 PENNSYLVANIA ELECTRIC COMPANY 25-0718085
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
Indicate by check mark whether each of the registrants (1) has filed
all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days.
Yes X No
---- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date:
OUTSTANDING
CLASS AS OF NOVEMBER 13, 2002
----- -----------------------
FirstEnergy Corp., $.10 par value 297,636,276
Ohio Edison Company, no par value 100
The Cleveland Electric Illuminating Company,
no par value 79,590,689
The Toledo Edison Company, $5 par value 39,133,887
Pennsylvania Power Company, $30 par value 6,290,000
Jersey Central Power & Light Company, $10 par value 15,371,270
Metropolitan Edison Company, no par value 859,500
Pennsylvania Electric Company, $20 par value 5,290,596
FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland
Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power &
Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company
common stock; Ohio Edison Company is the sole holder of Pennsylvania Power
Company common stock.
This combined Form 10-Q is separately filed by FirstEnergy Corp.,
Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light
Company, Metropolitan Edison Company and Pennsylvania Electric Company.
Information contained herein relating to any individual registrant is filed by
such registrant on its own behalf. No registrant makes any representation as to
information relating to any other registrant, except that information relating
to any of the FirstEnergy subsidiary registrants is also attributed to
FirstEnergy.
This Form 10-Q 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, legislative and regulatory changes (including revised environmental
requirements), the availability and cost of capital, ability to accomplish or
realize anticipated benefits from strategic initiatives and other similar
factors.
TABLE OF CONTENTS
Pages
Part I. Financial Information
Notes to Financial Statements................................ 1-11
FirstEnergy Corp.
Consolidated Statements of Income............................ 12
Consolidated Balance Sheets.................................. 13-14
Consolidated Statements of Cash Flows........................ 15
Report of Independent Accountants............................ 16
Management's Discussion and Analysis of Results of
Operations and Financial Condition........................... 17-30
Ohio Edison Company
Consolidated Statements of Income............................ 31
Consolidated Balance Sheets.................................. 32-33
Consolidated Statements of Cash Flows........................ 34
Report of Independent Accountants............................ 35
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 36-40
The Cleveland Electric Illuminating Company
Consolidated Statements of Income............................ 41
Consolidated Balance Sheets.................................. 42-43
Consolidated Statements of Cash Flows........................ 44
Report of Independent Accountants............................ 45
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 46-50
The Toledo Edison Company
Consolidated Statements of Income............................ 51
Consolidated Balance Sheets.................................. 52-53
Consolidated Statements of Cash Flows........................ 54
Report of Independent Accountants............................ 55
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 56-60
Pennsylvania Power Company
Statements of Income......................................... 61
Balance Sheets............................................... 62-63
Statements of Cash Flows..................................... 64
Report of Independent Accountants............................ 65
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 66-69
Jersey Central Power & Light Company
Consolidated Statements of Income............................ 70
Consolidated Balance Sheets.................................. 71-72
Consolidated Statements of Cash Flows........................ 73
Report of Independent Accountants............................ 74
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 75-80
TABLE OF CONTENTS (Cont'd)
Pages
Metropolitan Edison Company
Consolidated Statements of Income............................ 81
Consolidated Balance Sheets.................................. 82-83
Consolidated Statements of Cash Flows........................ 84
Report of Independent Accountants............................ 85
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 86-91
Pennsylvania Electric Company
Consolidated Statements of Income............................ 92
Consolidated Balance Sheets.................................. 93-94
Consolidated Statements of Cash Flows........................ 95
Report of Independent Accountants............................ 96
Management's Discussion and Analysis of Results of
Operations and Financial Condition......................... 97-102
Controls and Procedures...................................... 103
Part II. Other Information
PART I. FINANCIAL INFORMATION
- ------------------------------
FIRSTENERGY CORP. AND SUBSIDIARIES
OHIO EDISON COMPANY AND SUBSIDIARIES
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
PENNSYLVANIA POWER COMPANY
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
1 - FINANCIAL STATEMENTS:
The principal business of FirstEnergy Corp. (FirstEnergy) is the
holding, directly or indirectly, of all of the outstanding common stock of its
eight principal electric utility operating subsidiaries, Ohio Edison Company
(OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison
Company (TE), Pennsylvania Power Company (Penn), American Transmission Systems,
Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison
Company (Met-Ed) and Pennsylvania Electric Company (Penelec). These utility
subsidiaries are referred to throughout as "Companies." Penn is a wholly owned
subsidiary of OE. FirstEnergy's results include the results of JCP&L, Met-Ed and
Penelec from the November 7, 2001 merger date with GPU, Inc., the former parent
company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the
purchase method of accounting and the applicable effects were reflected on the
financial statements of JCP&L, Met-Ed and Penelec as of the merger date.
Accordingly, the post-merger financial statements reflect a new basis of
accounting, and pre-merger period and post-merger period financial results of
JCP&L, Met-Ed and Penelec (separated by a heavy black line) are presented.
FirstEnergy's consolidated financial statements also include its other principal
subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services
Group, LLC (FEFSG); MYR Group, Inc. (MYR); 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. FEFSG is
the parent company of several heating, ventilating, air conditioning and energy
management companies, and MYR is a utility infrastructure construction service
company. MARBEL is a fully integrated natural gas company. GPU Capital owns and
operates electric distribution systems in foreign countries 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.
The condensed unaudited financial statements of FirstEnergy and each
of the Companies reflect all normal recurring adjustments that, in the opinion
of management, are necessary to fairly present results of operations for the
interim periods. These statements should be read in conjunction with the
financial statements and notes included in the combined Annual Report on Form
10-K for the year ended December 31, 2001 for FirstEnergy and the Companies.
Significant intercompany transactions have been eliminated. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities. Actual results
could differ from those estimates. The reported results of operations are not
indicative of results of operations for any future period. Certain prior year
amounts have been reclassified to conform with the current year presentation.
Preferred Securities
The sole assets of the CEI subsidiary trust that is the obligor on
the preferred securities included in FirstEnergy's and CEI's capitalization are
$103,093,000 principal amount of 9% Junior Subordinated Debentures of CEI due
December 31, 2006.
Met-Ed and Penelec have each formed statutory business trusts for the
issuance of $100 million each of preferred securities due 2039. 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, the sole assets and
sources of revenues of each trust are the preferred securities of the applicable
limited partnership, whose sole assets are in the 7.35% and 7.34% subordinated
debentures (aggregate principal amount of $103.1 million each) 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.
1
Securitized Transition Bonds
On June 11, 2002, JCP&L Transition Funding LLC (the 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 or did not purchase any of the transition bonds,
which are included in long-term debt on FirstEnergy's and JCP&L's Consolidated
Balance Sheet. 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 is a presently existing property right
which includes the right to charge, collect and receive from JCP&L's utility
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.
Derivative Accounting
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.
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. The current net deferred loss of $116.7 million included in
Accumulated Other Comprehensive Loss (AOCL) as of September 30, 2002, for
derivative hedging activity as compared to the June 30, 2002 balance of $133.0
million in AOCL, resulted from $13.2 million of gains related to current hedging
activity and $3.1 million of net hedge losses included in earnings during the
quarter. Approximately $17.8 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 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.
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
September 30, 2002, FirstEnergy's AOCL was approximately $118.7 million as
compared to the December 31, 2001 balance of $169.0 million. The 2002
year-to-date change is shown in the following table:
For the Nine Months
Ended Sept. 30, 2002
--------------------
(In thousands)
Net income...................................... $660,058
Other comprehensive income (loss), net of tax:
Derivative hedge transactions................. 52,752
All other..................................... (2,479)
--------
Comprehensive income............................ $710,331
========
2
2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:
Capital Expenditures
FirstEnergy's current forecast reflects expenditures of approximately
$3.2 billion (OE-$250 million, CEI-$353 million, TE-$209 million, Penn-$89
million, JCP&L-$541 million, Met-Ed-$309 million, Penelec-$355 million,
ATSI-$126 million, FES-$760 million and other subsidiaries-$257 million) for
property additions and improvements from 2002-2006, of which approximately $920
million (OE-$78 million, CEI-$130 million, TE-$88 million, Penn-$40 million,
JCP&L-$113 million, Met-Ed-$52 million, Penelec-$52 million, ATSI-$28 million,
FES-$186 million and other subsidiaries-$153 million) is applicable to 2002.
Investments for additional nuclear fuel during the 2002-2006 period are
estimated to be approximately $516 million (OE-$49 million, CEI-$41 million,
TE-$24 million, Penn-$31 million and FES-$371 million), of which approximately
$54 million (OE-$16 million, CEI-$17 million, TE-$11 million and Penn-$10
million) applies to 2002.
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 ratings contingent collateralization provisions. As
of September 30, 2002, outstanding guarantees and other assurances aggregated
$880.9 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 assets of FirstEnergy.
The likelihood that such parental guarantees of $831.8 million as of September
30, 2002 will increase amounts otherwise paid by FirstEnergy to meet its
obligations incurred in connection with ongoing energy and energy-related
activities is remote.
Most of FirstEnergy's surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees of $25.8 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. Requirements of 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 September 30, 2002, rating-contingent
collateralization totaled $23.3 million. FirstEnergy monitors these
collateralization provisions and updates its total exposure monthly.
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 $235 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2002 through 2006.
The Companies are required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies believe they are in compliance with the current SO2 and
nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule
imposes uniform reductions of NOx emissions (an approximate 85% reduction in
utility plant NOx emissions from projected 2007 emissions) across a region of
nineteen states and the District of Columbia, including 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
3
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
which are currently scheduled for hearings in February 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 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 September 30, 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 a non-bypassable societal benefits charge. The Companies have total
accrued liabilities aggregating approximately $57.9 million (JCP&L-$50.7
million, CEI-$2.8 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-0.4
million and other-$3.6 million) as of September 30, 2002. FirstEnergy does not
believe environmental remediation costs will have a material adverse effect on
its financial condition, cash flows or results of operations.
Other Commitments and Contingencies
GPU made significant investments in foreign businesses and facilities
through its GPU Power subsidiary. Although FirstEnergy attempts 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 $270 million as of September 30,
2002. The lenders include the Overseas Private Investment Corporation, US Export
Import Bank and a commercial bank syndicate. FirstEnergy has also 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.
4
3 - PENDING DIVESTITURES:
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 Accounting Principles Board Opinion
(APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," with physically and operationally separable
activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11,
"Allocation of Purchase Price to Assets to Be Sold," 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 Consolidated Statements of Income. Additionally,
assets and liabilities of these international operations were segregated under
separate captions in the Consolidated Balance Sheet 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, FirstEnergy's wholly owned holding company of
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 interest in Avon for approximately $1.9 billion (including the
assumption of $1.7 billion of debt). FirstEnergy 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) from Aquila for its 79.9 percent interest. As of May 8,
2002, Avon had approximately $380 million in cash and cash equivalents.
FirstEnergy and Aquila together own all of the outstanding shares of Avon
through a jointly owned subsidiary, with each company having a 50-percent 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 until February 6, 2002. However, the
revision to the initial offer by Aquila caused a reversal of this accounting in
the first quarter of 2002, resulting in the recognition of a cumulative effect
of a change in accounting which increased net income by $31.7 million. This
resulted from the application of guidance provided by 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," accounting under EITF Issue No. 87-11,
recognizing the net income of Avon from November 7, 2001 to February 6, 2002
that previously was not recognized by FirstEnergy in its consolidated earnings
as discussed above.
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. Based on its assessment of the
probability of sale and several other key assumptions such as pricing, growth of
customer base and the timing of an economic recovery, FirstEnergy has determined
that it is not probable that the current economic conditions in Argentina have
eroded the fair value recorded for Emdersa; as a result, an impairment writedown
of this investment is not warranted as of September 30, 2002. FirstEnergy will
continue to assess the potential impact of these and other related events on the
realizability of the value recorded for Emdersa. FirstEnergy continues to pursue
divesting Emdersa and, in accordance with EITF Issue No. 87-11, has classified
its assets and liabilities in the Consolidated Balance Sheet as "Assets Pending
Sale" and "Liabilities Related to Assets Pending Sale". Potential investors
recently retained a financial advisor to assist in the due diligence process and
FirstEnergy believes it is probable that preliminary negotiations with those
investors will be completed in 2002. If FirstEnergy has not completed the sale
of all of its interest in Emdersa or has not reached a definitive agreement in
2002 to sell such interest, those assets would no longer be classified as
"Assets Pending Sale" on FirstEnergy's Consolidated Balance Sheet and Emdersa's
results of operations would be included on FirstEnergy's Consolidated Statement
of Income. In addition, Emdersa's cumulative results of operations (from
November 7, 2001 through the date that it would become probable that a
definitive sale agreement for all of FirstEnergy's interest would not be reached
in 2002) would be reflected on FirstEnergy's Consolidated Statement of Income as
a "Cumulative Effect of a Change in Accounting" under EITF 90-6. As of September
30, 2002, that adjustment would have reduced FirstEnergy's net income by
approximately $94 million ($0.32 per share of common stock). Other international
operations are being considered for sale; however, as of the merger date those
sales were not judged to be probable of occurring in 2002.
5
The following table shows the net changes in "Assets Pending Sale"
and "Liabilities Related to Assets Pending Sale" from December 31, 2001 to
September 30, 2002:
Dec. 31, Year-to-Date Sept. 30,
2001 Changes 2002
-------- ------------ ---------
(In millions)
Assets Pending Sale:
Current assets................................ $ 595 $ (574) $ 21
Property, plant and equipment................. 1,915 (1,838) 77
Investments................................... 142 (142) --
Deferred charges.............................. 766 (614) 152
------ ------- ----
Total....................................... 3,418 (3,168) 250
Liabilities Related to Assets Pending Sale:
Current liabilities........................... 1,055 (953) 102
Long-term debt................................ 1,432 (1,432) --
Deferred credits.............................. 468 ( 464) 4
------ ------- ----
Total....................................... 2,955 (2,849) 106
Net Assets Pending Sale....................... $ 463 $ (319) $144
====== ======= ====
The September 30, 2002 balance represents the assets and liabilities
of the Argentina operations, Emdersa. The year-to-date change is primarily the
result of the sale of Avon.
Sale of Generating Assets
In November 2001, FirstEnergy had 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 is reserving 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. FirstEnergy is
pursuing opportunities with other parties who have expressed interest in
purchasing the plants. FirstEnergy expects to conclude a bid process in the
fourth quarter of 2002, with the objective of executing a sales agreement by
year-end if a bid is deemed acceptable. Any net after-tax gain from such sale,
based on the difference between the sale price of the plants and their market
price used in the Ohio restructuring transition plan, will be credited to
customers by reducing the transition cost recovery period. If FirstEnergy has
not executed a sales agreement by year-end, it would need to reflect up to $58
million of previously unrecognized depreciation and other transaction costs for
these plants from November 2001 through September 2002 on its Consolidated
Statement of Income.
4 - REGULATORY MATTERS:
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included the following provisions which are reflected in
the Companies' respective state regulatory plans:
o allowing the Companies' electric customers to select their generation
suppliers;
o establishing provider of last resort (PLR) obligations to non-shopping
customers in the Companies' service areas;
o allowing recovery of potentially stranded investment (or transition
costs);
o itemizing (unbundling) the current price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
o deregulating the Companies' electric generation businesses; and
o continuing regulation of the Companies' transmission and distribution
systems.
Ohio
FirstEnergy's transition plan (which it filed on behalf of OE, CEI
and TE (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 FirstEnergy's 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
6
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.
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). Based on actual shopping levels through October 2002,
FirstEnergy has achieved all of its required 20% customer shopping goals and
there is no longer risk of 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 New Jersey Board of Public Utilities
(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 transition bonds through a new wholly owned subsidiary, JCP&L
Transition Funding LLC, in May 2002, which is recognized on the Consolidated
Balance Sheet.
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 nonutility generation (NUG) agreements exceed
amounts collected through BGS and MTC rates. As of September 30, 2002, the
accumulated deferred cost balance totaled approximately $482 million. The Final
Order 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. Rate
filing hearings are anticipated in the first quarter of 2003. The NJBPU has
directed the Office of Administrative Law to provide an initial recommended
decision by May 1, 2003; the Judge has indicated she would request an extension.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electric demands of
all customers who have not selected an alternative supplier. The auction, which
ended on February 13, 2002 and was approved by the NJBPU on February 15, 2002,
removed JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through
July 31, 2003. The auction provides a transitional mechanism and a different
model for the procurement of BGS commencing August 1, 2003 may be adopted.
Pennsylvania
The Pennsylvania Public Utility Commission (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.
7
As a result of their generating asset divestitures, Met-Ed and
Penelec obtain their supply of electricity to meet their PLR obligations almost
entirely from contracted and open market purchases. 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 rate
relief. 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 are below their respective
capped generation rates, that difference will reduce costs that had been
deferred for recovery in future periods. This deferral accounting procedure will
cease on December 31, 2005. Thereafter, costs which had been deferred through
that date would be recoverable through application of competitive transition
charge (CTC) revenues received by Met-Ed and Penelec through December 31, 2010.
Met-Ed's and Penelec's PLR obligations extend through December 31, 2010; during
that period CTC revenues will be applied first to PLR costs, then to non-NUG
stranded costs and finally to NUG stranded costs. Met-Ed and Penelec would be
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 be written off at the
time such nonrecovery becomes probable.
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to an affiliate company, FES, through a wholesale power sale. The
PLR sale runs through the end of 2002 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 to FES. Met-Ed and Penelec will continue to defer those cost
differences between NUG contract rates and the rates reflected in their capped
generation rates.
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 Supreme Court of
Pennsylvania. In September 2002, Met-Ed and Penelec established reserves for
their PLR deferred energy costs which aggregated $287.1 million (Met-Ed $143.2
million and Penelec $143.9 million). The reserves reflect the potential adverse
impact of a pending Pennsylvania Supreme Court decision whether to review the
Commonwealth Court ruling. In the interim financial statements in 2002,
FirstEnergy, Met-Ed and Penelec had previously disclosed, in consultation with
its independent accountants, that the finalization of that potential
pre-acquisition contingency relating to the FirstEnergy/GPU merger would be
reflected as an adjustment to the allocation of the purchase price prior to the
end of the third quarter of 2002. In connection with FirstEnergy finalizing the
purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter
of 2002, Met-Ed and Penelec, after further consultation with its independent
accountants, revised the previously disclosed accounting for this potential
pre-acquisition contingency. Accordingly, Met-Ed and Penelec will be amending
the interim financial statements included in their Form 10-Q filings for the
quarters ended March 31, 2002 and June 30, 2002 to reflect establishment of the
reserve in the first quarter of 2002. The following tables summarize the impact
on net income for Met-Ed and Penelec for the first and second quarters of 2002.
Met-Ed 3 Months Ended, 6 Months Ended,
- ------ ----------------------------- ---------------
March 31, 2002 June 30, 2002 June 30, 2002
-------------- ------------- -------------
Net income as previously reported....... $19,118 $19,667 $38,785
Effect of revision...................... 7,494 (3,706) 3,788
------- ------- -------
Net income as revised................... $26,612 $15,961 $42,573
======= ======= =======
Penelec 3 Months Ended, 6 Months Ended,
- ------- ----------------------------- ---------------
March 31, 2002 June 30, 2002 June 30, 2002
-------------- ------------- -------------
Net income as previously reported....... $14,147 $11,245 $25,392
Effect of revision...................... 4,692 (4,390) 302
------- ------- -------
Net income as revised................... $18,839 $ 6,855 $25,694
======= ======= =======
8
Their respective financial statements for the three months and nine
months ended September 30, 2002, reflect the effect of the retroactive
application. Since these revisions are not significant to FirstEnergy's
consolidated financial statements for these periods, there will be no
restatement of FirstEnergy's consolidated financial statements. FirstEnergy
recorded an aggregate non-cash charge of $55.8 million ($32.6 million net of
tax) for the deferred costs incurred subsequent to the merger - $30.7 million
($17.9 million net of tax) by Met-Ed and $25.1 million ($14.7 million net of
tax) by Penelec. The reserve for the remaining $231.3 million of deferred costs
(Met-Ed-$112.5 million and Penelec-$118.8 million) increased goodwill by an
aggregate net of tax amount of $135.3 million (Met-Ed-$65.8 million and
Penelec-$69.5 million).
5 - NEW ACCOUNTING STANDARDS:
The Financial Accounting Standards Board (FASB) approved SFAS 141,
"Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on
June 29, 2001. SFAS 141 requires all business combinations initiated after June
30, 2001, to be accounted for using purchase accounting. The provisions of the
new standard relating to the determination of goodwill and other intangible
assets have been applied to the GPU merger, which was accounted for as a
purchase transaction, and have not materially affected the accounting for this
transaction. Under SFAS 142, amortization of existing goodwill ceased January 1,
2002. Instead, goodwill will be tested for impairment at least on an annual
basis - based on the results of the transition analysis, no impairment of
goodwill is required. Prior to the adoption of SFAS 142, FirstEnergy amortized
about $57 million ($.25 per share of common stock) of goodwill annually. There
was no goodwill amortization in 2001 associated with the GPU merger under the
provisions of the new standard.
The following table shows what net income and earnings per share
would have been if goodwill amortization, net of tax, had been excluded from
prior periods:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
---- ---- ---- ----
(In thousands, except per share amounts)
Reported net income.............................. $310,255 $234,087 $660,058 $477,814
Add back goodwill amortization (net of tax)...... -- 13,874 -- 41,013
-------- -------- -------- --------
Adjusted net income.............................. $310,255 $247,961 $660,058 $518,827
======== ======== ======== ========
Basic earnings per common share:
Reported earnings per share................... $1.06 $1.07 $2.25 $2.19
Goodwill amortization......................... -- 0.06 -- 0.19
----- ----- ----- -----
Adjusted earnings per share................... $1.06 $1.13 $2.25 $2.38
===== ===== ===== =====
Diluted earnings per common share:
Reported earnings per share................... $1.05 $1.06 $2.24 $2.18
Goodwill amortization......................... -- 0.06 -- 0.19
----- ----- ----- -----
Adjusted earnings per share................... $1.05 $1.12 $2.24 $2.37
===== ===== ===== =====
The net change of $171 million in the goodwill balance as of
September 30, 2002 of approximately $5.77 billion as compared to the December
31, 2001 balance of approximately $5.60 billion, primarily reflects the $135.3
million net of tax effect of the Pennsylvania PLR reserve of approximately
$231.3 million as discussed in Note 4 - "Regulatory Matters - Pennsylvania" and
further refinements of the initial purchase price allocation.
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. 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 various applicable legal obligations as
defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
In September 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The Statement also supersedes the accounting and reporting
provisions of APB 30. FirstEnergy's adoption of this Statement, effective
January 1, 2002, resulted in its accounting for any future impairments or
disposals of long-lived assets under the provisions of SFAS 144, but did not
change the accounting principles used in previous asset impairments or
disposals. Application of SFAS 144 did not have a major impact on accounting for
impairments or disposal transactions compared to the prior application of SFAS
121 or APB 30.
9
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," 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 will
be 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.
On October 25, 2002, the Emerging Issues Task Force (EITF) reached a
consensus in 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," to rescind EITF Issue No. 98-10 (and related
interpretative guidance). Rescinding EITF No. 98-10 eliminates mark-to-market
accounting for energy trading contracts that are not derivatives under SFAS 133.
This guidance will be effective for all new contracts entered into after October
25, 2002 and the impact of its initial application will be reported as a change
in accounting principle. Additionally, the EITF concluded that gains and losses
on all derivative instruments under SFAS 133 that are held for trading purposes
should be netted against related purchases or sales in the income statement.
This new presentation requirement will be effective for periods beginning after
December 15, 2002. FirstEnergy is not impacted by the rescission of EITF 98-10
and does not anticipate a material effect from the net presentation requirement.
6 - SEGMENT INFORMATION:
FirstEnergy operates under the following reportable segments:
regulated services, competitive services and other (primarily corporate support
services and international operations). FirstEnergy's primary segment is
regulated services, which include eight 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. Certain prior year
amounts have been reclassified to conform with the current year presentation.
The regulated services segment designs, constructs, operates and
maintains FirstEnergy's regulated transmission and distribution systems. It also
provides generation services to regulated franchise customers who have not
chosen an alternative, competitive generation supplier. The regulated services
segment obtains a portion of its required generation through power supply
agreements with the competitive services segment.
10
Segment Financial Information
-----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
--------- ----------- ----- ----------- ------------
(In millions)
Three Months Ended:
- -------------------
September 30, 2002
------------------
External revenues..................... $ 2,616 $ 934 $ 20 $ 2 (a) $ 3,572
Internal revenues..................... 261 452 116 (829) (b) --
Total revenues..................... 2,877 1,386 136 (827) 3,572
Depreciation and amortization......... 238 8 8 -- 254
Net interest charges.................. 140 17 77 (14) (b) 220
Income taxes.......................... 282 (10) (33) -- 239
Income before cumulative effect of
a change in accounting............. 383 (15) (58) -- 310
Net income (loss)..................... 383 (15) (58) -- 310
Total assets.......................... 29,915 2,174 2,077 -- 34,166
Property additions.................... 150 69 56 -- 275
September 30, 2001
------------------
External revenues..................... $ 1,457 $ 450 $ 2 $ 43 (a) $ 1,952
Internal revenues..................... 308 484 66 (858) (b) --
Total revenues..................... 1,765 934 68 (815) 1,952
Depreciation and amortization......... 197 7 7 -- 211
Net interest charges.................. 154 8 8 (46) (b) 124
Income taxes.......................... 188 (3) (4) -- 181
Income before cumulative effect of
a change in accounting............. 246 (4) (8) -- 234
Net income (loss)..................... 246 (4) (8) -- 234
Total assets.......................... 15,460 2,113 505 -- 18,078
Property additions.................... 180 107 4 -- 291
Nine Months Ended:
- ------------------
September 30, 2002
------------------
External revenues..................... $ 6,772 $2,308 $ 229 $ 14 (a) $ 9,323
Internal revenues..................... 793 1,279 358 (2,430) (b) --
Total revenues..................... 7,565 3,587 587 (2,416) 9,323
Depreciation and amortization......... 714 21 32 -- 767
Net interest charges.................. 458 34 282 (43) (b) 731
Income taxes.......................... 657 (47) (106) -- 504
Income before cumulative effect of
a change in accounting............. 854 (68) (158) -- 628
Net income (loss)..................... 854 (68) (126) -- 660
Total assets.......................... 29,915 2,174 2,077 -- 34,166
Property additions.................... 414 179 102 -- 695
September 30, 2001
------------------
External revenues..................... $ 4,026 $1,582 $ 4 $ 130 (a) $ 5,742
Internal revenues..................... 865 1,432 195 (2,492) (b) --
Total revenues..................... 4,891 3,014 199 (2,362) 5,742
Depreciation and amortization......... 608 15 22 -- 645
Net interest charges.................. 406 17 24 (76) (b) 371
Income taxes.......................... 413 (31) 3 -- 385
Income before cumulative effect of
a change in accounting............. 528 (45) 3 -- 486
Net income (loss)..................... 528 (53) 3 -- 478
Total assets.......................... 15,460 2,113 505 -- 18,078
Property additions.................... 269 285 14 -- 568
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.
11
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------- ---------- ---------- ----------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(In thousands, except per share amounts)
REVENUES:
Electric utilities..................................... $2,717,461 $1,437,023 $6,981,753 $4,008,823
Unregulated businesses................................. 854,874 514,623 2,341,447 1,732,710
---------- ---------- ---------- ----------
Total revenues..................................... 3,572,335 1,951,646 9,323,200 5,741,533
---------- ---------- ---------- ----------
EXPENSES:
Fuel and purchased power............................... 1,388,830 300,526 2,916,472 925,633
Purchased gas.......................................... 95,799 121,564 447,980 647,938
Other operating expenses............................... 887,423 667,003 2,834,230 1,956,252
Provision for depreciation and amortization............ 253,917 210,764 767,450 644,584
General taxes.......................................... 176,850 112,292 493,944 323,900
---------- ---------- ---------- ----------
Total expenses..................................... 2,802,819 1,412,149 7,460,076 4,498,307
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST AND INCOME TAXES................... 769,516 539,497 1,863,124 1,243,226
---------- ---------- ---------- ----------
NET INTEREST CHARGES:
Interest expense....................................... 212,477 114,468 685,824 349,029
Capitalized interest................................... (6,303) (7,016) (18,722) (28,135)
Subsidiaries' preferred stock dividends................ 14,223 16,674 63,399 50,527
---------- ---------- ---------- ----------
Net interest charges............................... 220,397 124,126 730,501 371,421
---------- ---------- ---------- ----------
INCOME TAXES.............................................. 238,864 181,284 504,265 385,492
---------- ---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE
IN ACCOUNTING.......................................... 310,255 234,087 628,358 486,313
Cumulative effect of accounting change (net of income
taxes (benefit) of $13,600,000 and $(5,839,000),
respectively)(Notes 1 and 3)........................... -- -- 31,700 (8,499)
---------- ---------- ---------- ----------
NET INCOME................................................ $ 310,255 $ 234,087 $ 660,058 $ 477,814
========== ========== ========== ==========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before cumulative effect of accounting change... $1.06 $1.07 $2.14 $2.23
Cumulative effect of accounting change (net of income taxes)
(Notes 1 and 3)...................................... -- -- .11 (.04)
----- ----- ----- -----
Net income........................................... $1.06 $1.07 $2.25 $2.19
===== ===== ===== =====
WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING............................................ 293,328 218,594 293,066 218,358
======= ======= ======= =======
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before cumulative effect of accounting change... $1.05 $1.06 $2.13 $2.22
Cumulative effect of accounting change (net of income taxes)
(Notes 1 and 3)...................................... -- -- .11 (.04)
----- ----- ----- -----
Net income........................................... $1.05 $1.06 $2.24 $2.18
===== ===== ===== =====
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING............................................ 294,277 220,165 294,385 219,470
======= ======= ======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $1.125 $1.125
===== ===== ====== ======
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
12
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- --------------
(In thousands)
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents................................................. $ 280,547 $ 220,178
Receivables-
Customers (less accumulated provisions of $69,382,000 and $65,358,000,
respectively, for uncollectible accounts)............................. 1,139,367 1,074,664
Other (less accumulated provisions of $9,438,000 and $7,947,000,
respectively, for uncollectible accounts)............................. 560,022 473,550
Materials and supplies, at average cost-
Owned................................................................... 262,955 256,516
Under consignment....................................................... 156,530 141,002
Other..................................................................... 242,155 336,610
----------- -----------
2,641,576 2,502,520
----------- -----------
ASSETS PENDING SALE (Note 3)................................................. 249,780 3,418,225
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................................ 20,363,677 19,981,749
Less-Accumulated provision for depreciation............................... 8,505,428 8,161,022
----------- -----------
11,858,249 11,820,727
Construction work in progress............................................. 684,859 607,702
----------- -----------
12,543,108 12,428,429
----------- -----------
INVESTMENTS:
Capital trust investments................................................. 1,095,586 1,166,714
Nuclear plant decommissioning trusts...................................... 1,024,332 1,014,234
Letter of credit collateralization........................................ 277,763 277,763
Pension investments....................................................... 295,018 273,542
Other..................................................................... 962,943 898,311
----------- -----------
3,655,642 3,630,564
----------- -----------
DEFERRED CHARGES:
Regulatory assets......................................................... 8,351,717 8,912,584
Goodwill.................................................................. 5,771,856 5,600,918
Other..................................................................... 951,875 858,273
----------- -----------
15,075,448 15,371,775
----------- -----------
$34,165,554 $37,351,513
=========== ===========
13
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- --------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... $ 1,477,925 $ 1,867,657
Short-term borrowings..................................................... 1,153,569 614,298
Accounts payable.......................................................... 789,846 704,184
Accrued taxes............................................................. 521,962 418,555
Other..................................................................... 1,119,752 1,064,763
----------- -----------
5,063,054 4,669,457
----------- -----------
LIABILITIES RELATED TO ASSETS PENDING SALE (Note 3).......................... 106,308 2,954,753
----------- -----------
CAPITALIZATION:
Common stockholders' equity-
Common stock, $.10 par value, authorized 375,000,000 shares -
297,636,276 shares outstanding........................................ 29,764 29,764
Other paid-in capital................................................... 6,113,191 6,113,260
Accumulated other comprehensive loss.................................... (118,730) (169,003)
Retained earnings....................................................... 1,852,298 1,521,805
Unallocated employee stock ownership plan common stock -
4,202,566 and 5,117,375 shares, respectively.......................... (83,749) (97,227)
----------- -----------
Total common stockholders' equity................................... 7,792,774 7,398,599
Preferred stock of consolidated subsidiaries-
Not subject to mandatory redemption..................................... 335,123 480,194
Subject to mandatory redemption......................................... 19,299 65,406
Subsidiary-obligated mandatorily redeemable preferred securities.......... 409,763 529,450
Long-term debt............................................................ 11,092,318 11,433,313
----------- -----------
19,649,277 19,906,962
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 2,697,511 2,684,219
Accumulated deferred investment tax credits............................... 241,792 260,532
Nuclear plant decommissioning costs....................................... 1,237,938 1,201,599
Power purchase contract loss liability.................................... 3,139,107 3,566,531
Other postretirement benefits............................................. 891,973 838,943
Other..................................................................... 1,138,594 1,268,517
----------- -----------
9,346,915 9,820,341
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
----------- -----------
$34,165,554 $37,351,513
=========== ===========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these balance sheets.
14
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ------------------------
2002 2001 2002 2001
--------- --------- ---------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 310,255 $ 234,087 $ 660,058 $ 477,814
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation and amortization........ 253,917 210,764 767,450 644,584
Nuclear fuel and lease amortization................ 20,191 23,247 60,754 71,448
Other amortization, net............................ (5,381) (3,111) (13,304) (10,783)
Deferred costs recoverable as regulatory assets.... (152,336) -- (291,406) --
Deferred income taxes, net......................... 37,831 (29,749) 81,252 (65,057)
Investment tax credits, net........................ (6,767) (4,980) (20,480) (14,966)
Cumulative effect of accounting change............. -- -- (45,300) 14,338
Receivables........................................ (67,608) (69,509) (151,175) (45,924)
Materials and supplies............................. (18,388) (16,068) (21,967) (60,330)
Accounts payable................................... 47,888 79,982 85,662 (27,697)
Accrued taxes...................................... 16,687 115,101 103,407 118,255
Accrued interest................................... 79,063 4,765 59,507 6,034
Other.............................................. 153,065 46,194 120,166 (126,397)
--------- --------- ---------- ---------
Net cash provided from operating activities...... 668,417 590,723 1,394,624 981,319
--------- --------- ---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 317,890 7,128 684,620 262,627
Short-term borrowings, net........................... 508,720 56,232 539,271 114,713
Redemptions and Repayments-
Common stock......................................... -- -- -- 15,308
Preferred stock...................................... 313,517 6,000 503,816 16,716
Long-term debt....................................... 871,608 198,514 1,250,251 294,075
Common stock dividend payments......................... 109,963 81,942 329,565 245,559
--------- --------- ---------- ---------
Net cash used for financing activities........... 468,478 223,096 859,741 194,318
--------- --------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... 274,923 291,276 694,614 567,774
Proceeds from sale of Midlands......................... -- -- (155,034) --
Avon cash and cash equivalents (Note 3)................ -- -- (31,326) --
Net assets held for sale............................... 33,385 -- 31,326 --
Cash investments....................................... 4,310 1,799 (59,712) (30,802)
Other.................................................. (34,176) 104,177 (5,354) 123,693
--------- --------- ---------- ---------
Net cash used for investing activities........... 278,442 397,252 474,514 660,665
--------- --------- ---------- ---------
Net increase (decrease) in cash and cash equivalents...... (78,503) (29,625) 60,369 126,336
Cash and cash equivalents at beginning of period*......... 359,050 205,219 220,178 49,258
--------- --------- ---------- ---------
Cash and cash equivalents at end of period*............... $ 280,547 $ 175,594 $ 280,547 $ 175,594
========= ========= ========== =========
* Excludes amounts in "Assets Pending Sale" on the Consolidated Balance Sheets.
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
15
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of FirstEnergy Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy
Corp. and its subsidiaries as of September 30, 2002, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 30, 2002. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
16
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
FirstEnergy Corp. is a registered public utility holding company. Its
subsidiaries and affiliates provide regulated and competitive electricity and
other energy and energy-related services (see Results of Operations - Business
Segments).
FirstEnergy - which acquired the former GPU, Inc., in November 2001 -
provides domestic regulated electric distribution services through its seven
wholly owned electric utility subsidiaries. Ohio Edison Company (OE), The
Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn)
and The Toledo Edison Company (TE) provide regulated electric distribution
services to customers in Ohio and Pennsylvania, and American Transmission
Systems, Inc. provides transmission services. Metropolitan Edison Company
(Met-Ed), Pennsylvania Electric Company (Penelec), and Jersey Central Power &
Light Company (JCP&L) - which were acquired through the GPU merger - provide
regulated electric distribution and transmission services to customers in
Pennsylvania and New Jersey.
Other FirstEnergy subsidiaries and affiliates sell energy and
energy-related products and services, including electricity, natural gas and
energy management services, in competitive markets. These products and services
are often bundled under master contracts. Among FirstEnergy subsidiaries and
affiliates supplying services in competitive markets are FirstEnergy Solutions
(FES), MARBEL Energy Corporation, FirstEnergy Facilities Services Group, LLC,
and MYR Group, Inc. FirstEnergy also offers electric services through
international operations that were acquired in the GPU merger, including GPU
Capital, Inc., and GPU Power, Inc. GPU Capital, Inc. and its subsidiaries
provide electric distribution services and GPU Power, Inc., and its subsidiaries
develop, own and operate electric generation facilities.
Results of Operations
- ---------------------
Net income in the third quarter of 2002 was $310.3 million, or basic
earnings of $1.06 per share of common stock ($1.05 diluted), compared to $234.1
million, or basic earnings of $1.07 per share of common stock ($1.06 diluted) in
the third quarter of 2001. During the first nine months of 2002, net income was
$660.1 million, or basic earnings of $2.25 per share of common stock ($2.24
diluted), compared to net income of $477.8 million, or basic earnings of $2.19
per share of common stock ($2.18 diluted) in the first nine months of 2001.
Results in the first nine months of 2002 and 2001 include the cumulative effect
of accounting changes (described below). Before the cumulative effect of
accounting changes, net income was $628.4 million in the first nine months of
2002, compared to $486.3 million for the same period of 2001. Basic earnings per
share of common stock before the cumulative effect of accounting changes were
$2.14 ($2.13 diluted) in the first nine months of 2002, compared to $2.23 ($2.22
diluted) in the first nine months of 2001.
Results for the third quarter and first nine months of 2002 reflect
the merger of FirstEnergy and GPU, which became effective on November 7, 2001,
and therefore include the results of the former GPU companies. As a result of
the merger, FirstEnergy issued nearly 73.7 million shares of its common stock,
which are reflected in the calculation of earnings per share of common stock in
the third quarter and year-to-date periods of 2002. Costs related to the
extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration)
reduced earnings by $0.19 per share in the third quarter and $0.28 per share in
the year-to-date period of 2002. The table following this paragraph shows
several one-time charges that resulted in a comparative net reduction to
earnings of $0.13 per share of common stock in the third quarter and $0.27 per
share of common stock in the first nine months of 2002, compared to the same
periods of 2001. The third quarter 2002 results included a one-time non-cash
charge of $0.11 per share that reflects the potential adverse impact of a
Pennsylvania Supreme Court decision on whether to review a Commonwealth Court
ruling that denied Met-Ed and Penelec the ability to defer the difference
between their actual energy costs and those reflected in their capped generation
rates (see State Regulatory Matters - Pennsylvania). In addition, Statement of
Financial Accounting Standards No. (SFAS) 142, "Goodwill and Other Intangible
Assets," implemented January 1, 2002, resulted in the cessation of goodwill
amortization. In the third quarter and first nine months of 2001, amortization
of goodwill reduced earnings per share of common stock (basic and diluted) by
$0.06 and $0.19, respectively.
One-time charges to earnings (discussed above) are summarized in the
following table:
17
One-Time Charges
- ----------------
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
---------------------- ---------------------
2002 2001 Change 2002 2001 Change
---- ---- ------ ---- ---- ------
(In millions)
Pre-Merger Companies:
- ---------------------
Severance costs - 2002............................ $11.3 $ -- $11.3 $ 11.3 -- $ 11.3
Early retirement costs - 2001..................... -- -- -- -- 8.8 (8.8)
Long-term derivative contract adjustment.......... -- -- -- 18.1 -- 18.1
Equity investment - bankruptcy.................... -- -- -- 30.4 -- 30.4
Telecommunications investment writedown........... -- -- -- 10.1 -- 10.1
Generation project cancellation................... -- -- -- 17.1 -- 17.1
----- ---- ----- ------ ----- ------
Total Pre-Merger Companies...................... 11.3 -- 11.3 87.0 8.8 78.2
Former GPU Companies:
- ---------------------
Reserve - PA Supreme Court(1)..................... 55.8 -- 55.8 55.8 -- 55.8
Telecommunications investment writedown........... -- -- -- 2.5 -- 2.5
----- ---- ----- ------ ----- ------
Total Former GPU Companies...................... 55.8 -- 55.8 58.3 -- 58.3
----- ---- ----- ------ ----- ------
Total One-Time Charges.......................... $67.1 $ -- $67.1 $145.3 $ 8.8 $136.5
===== ==== ===== ====== ===== ======
Effect on earnings per share of common stock
(basic and diluted)............................... $0.13 $ -- $0.13 $ 0.29 $0.02 $ 0.27
===== ==== ===== ====== ===== ======
(1) Represents a non-cash charge for the deferred costs incurred subsequent to
the merger with GPU for the potential adverse impact of a pending
Pennsylvania Supreme Court decision on whether to review the Commonwealth
Court ruling. The reserve established in September 2002 increased reported
purchased power costs for Met-Ed ($30.7 million) and Penelec ($25.1
million).
Revenues
Total revenues increased $1.6 billion in the third quarter and $3.6
billion in the first nine months of 2002, compared to the same periods in 2001.
Excluding results of the former GPU companies, total revenues increased by
$263.0 million or 13.5% in the third quarter and decreased by $81.6 million or
1.4% in the first nine months of 2002, compared to the corresponding periods of
2001. Sources of changes in pre-merger and post-merger revenues during the third
quarter and first nine months of 2002, compared with the corresponding periods
of 2001, are summarized in the following table:
Sources of Revenue Changes
--------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Pre-Merger Companies:
Electric Utilities (Regulated Services):
Retail electric sales......................... $ (61.0) $ (278.8)
Other revenues................................ 19.5 2.0
-------- --------
Total Electric Utilities........................ (41.5) (276.8)
-------- --------
Unregulated Businesses (Competitive Services):
Retail electric sales......................... 65.8 65.0
Wholesale electric sales...................... 317.4 442.0
Gas sales..................................... (12.8) (154.5)
Other businesses.............................. (65.9) (157.3)
-------- --------
Total Unregulated Businesses.................... 304.5 195.2
-------- --------
Total Pre-Merger Companies...................... 263.0 (81.6)
-------- --------
Former GPU Companies:
Electric utilities............................ 1,322.0 3,249.7
Unregulated businesses........................ 137.0 624.4
-------- --------
Total Former GPU Companies...................... 1,459.0 3,874.1
Intercompany Revenues........................... (101.3) (210.8)
-------- --------
Net Revenue Increase............................ $1,620.7 $3,581.7
======== ========
18
The following comparisons reflect variances for the pre-merger
companies only, excluding the revenues of the former GPU companies in the third
quarter and first nine months of 2002.
Electric Sales
Shopping by Ohio customers for alternative energy suppliers combined
with a weak economy reduced retail electric sales revenues for FirstEnergy's
pre-merger electric utility operating companies (EUOCs) by $61.0 million in the
third quarter and $278.8 million in the first nine months of 2002, compared to
the same periods of 2001. Kilowatt-hour sales to regulated retail customers
decreased 9.4% in the third quarter and 15.5% in the first nine months of 2002,
which reduced retail electric sales revenues by $48.9 million and $175.9
million, respectively. Sales of electric generation by alternative suppliers in
the EUOCs' franchise areas increased to 25.8% of total energy delivered in the
third quarter of 2002, compared to 15.1% in the same quarter last year. In the
first nine months of 2002, the EUOCs' share of franchise-area sales declined by
12.6 percentage points, compared to the same period of 2001. Although generation
kilowatt-hour sales continued to be adversely affected by economic conditions in
the regional industrial base, the third quarter impact was moderated by a
gradual recovery, as well as warmer summer weather, compared to the third
quarter of 2001.
Revenue from distribution deliveries increased by $16.1 million,
partially offsetting the lower generation sales revenues in the third quarter of
2002, compared to the same quarter of 2001, due to an overall 3.6% net increase
in kilowatt-hour deliveries to franchise customers. The net increase resulted
from additional kilowatt-hour deliveries to residential customers (11.0% higher)
and commercial and industrial customers (0.4% higher). Unusually hot summer
weather increased the air-conditioning demand of residential customers compared
to last year. During the first nine months of 2002, a 1.8% decline in
kilowatt-hour deliveries to franchise customers reduced retail electric sales
revenues by $26.0 million, compared to the same period in 2001. The reduced
distribution deliveries resulted from a 4.4% reduction in deliveries to the
commercial and industrial sectors, which were offset in part by a 4.7% increase
in kilowatt-hour deliveries to residential customers. While some evidence of a
modest economic recovery began in the first half of 2002, the recovery has not
been broad based.
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 - $28.2 million in the third
quarter and $76.6 million in the first nine months of 2002, compared to the same
periods of 2001. These reductions to revenue are deferred for future recovery
under FirstEnergy's Ohio transition plan and do not materially affect current
period earnings.
Retail electric sales revenue of the competitive services segment
increased $65.8 million in the third quarter of 2002 resulting from a doubling
of kilowatt-hour sales from the same quarter last year - accounting for all of
the increase in retail electric sales revenue of the competitive services
segment in the first nine months of 2002 compared to the same period of 2001.
The increase in FirstEnergy's competitive kilowatt-hour sales in 2002 occurred
primarily in Ohio. As of September 30, 2002, almost one-third of FirstEnergy's
Ohio franchise-area customers serviced by alternative suppliers were supplied by
FES.
Wholesale revenues increased $318.9 million in the third quarter and
$459.0 million in the year-to-date period of 2002, compared to the corresponding
periods last year. Kilowatt-hour sales to the wholesale markets correspondingly
more than doubled in the third quarter and first nine months of 2002, compared
to the same periods last year. The higher kilowatt-hour sales resulted from
increased availability of power for the wholesale market, due to additional
internal generation and increased shopping by retail customers from alternative
suppliers, which allowed FirstEnergy to take advantage of wholesale market
opportunities. Nonaffiliated retail energy suppliers having access to 1,120
megawatts of FirstEnergy's generation capacity made available under its
transition plan also contributed to the increase in sales to the wholesale
market in the year-to-date period of 2002.
Other Sales
- -----------
Other sales revenues declined by $78.7 million in the third quarter
and $311.8 million in the first nine months of 2002 from the corresponding
periods of 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 from decreased sales volume in
the third quarter and lower prices in the year-to-date period of 2002, compared
to the corresponding periods last year. Despite the reduced third quarter sales
volume and lower prices in the first nine months of 2002, gross margins for gas
sales improved (see Expenses). Reduced revenues from the facilities services
group also contributed to the decrease in other sales revenue in the third
quarter and year-to-date periods of 2002, compared to the same periods of 2001.
19
Expenses
- --------
Total expenses increased $1,390.7 million in the third quarter and
$2,961.8 million in the first nine months of 2002, compared to the corresponding
periods of 2001, including $1,185.3 million and $3,150.6 million of expenses
related to the former GPU companies, respectively. For the pre-merger companies,
total expenses increased by $308.0 million in the third quarter and $25.9
million in the first nine months of 2002, compared to the same periods of 2001.
Sources of changes in pre-merger and post-merger companies' expenses in the
third quarter and first nine months of 2002, compared to the prior year, are
summarized in the following table:
Sources of Expense Changes
--------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Pre-Merger Companies:
Fuel and purchased power......... $ 385.1 $ 369.0
Purchased gas.................... (25.8) (200.0)
Other operating expenses......... 2.4 (7.7)
Depreciation and amortization.... (63.5) (168.2)
General taxes.................... 9.8 32.8
-------- --------
Total Pre-Merger Companies....... 308.0 25.9
Former GPU Companies............... 1,185.3 3,150.6
Intercompany Expenses.............. (102.6) (214.7)
-------- --------
Net Expense Increase............... $1,390.7 $2,961.8
======== ========
The following comparisons reflect variances for the pre-merger
companies only, excluding the expenses of the former GPU companies in the third
quarter and first nine months of 2002.
Fuel and purchased power costs increased by $385.1 million in the
third quarter and by $369.0 million during the first nine months of 2002,
compared to the same periods of 2001. Fuel expense increased in both the third
quarter and first nine months of 2002 ($30.1 million and $90.2 million,
respectively) principally due to additional internal generation and an increased
mix of higher-cost fossil generation, as well as higher unit costs for coal
consumed in the year-to-date period of 2002. An extended outage at the
Davis-Besse nuclear plant (see Davis-Besse Restoration) contributed to declines
in nuclear generation of 15.1% and 11.6% in the third quarter and year-to-date
periods of 2002 from the same periods in 2001. Fossil plant production increased
significantly by 18.7% and 20.6% in the third quarter and first nine months of
2002, compared to the same periods of 2001. Overall, internal generation was
6.6% higher in the third quarter and 7.9% higher in the first nine months of
2002 than the corresponding periods of 2001. Purchased power costs increased
$355.0 million in the third quarter and $278.8 million in the first nine months
of 2002, compared to the same periods last year. The increases principally
resulted from the additional purchased power volume required to support higher
kilowatt-hour sales and reduced nuclear generation as a result of the
Davis-Besse unplanned extended outage.
Reduced purchase volumes and prices of natural gas in the third
quarter and lower prices in the year-to-date period of 2002, compared to the
corresponding periods last year, decreased purchased gas costs $25.8 million in
the third quarter and $200.0 million for the first nine months of 2002 from the
corresponding periods last year. The gross margins on gas sales improved by
$13.0 million in the third quarter and $45.5 million in the first nine months of
2002 from the same periods last year.
Other operating costs increased by $2.4 million in the third quarter
and decreased by $7.7 million in the first nine months of 2002, compared to the
corresponding periods of 2001. The slight increase in the third quarter resulted
from several larger offsetting factors. Nuclear operating costs increased $4.8
million - $40.5 million in incremental costs associated with the extended outage
at the Davis-Besse nuclear plant (see Davis-Besse Restoration) were
substantially offset by lower costs due to the absence in 2002 of a refueling
outage that occurred in the third quarter of 2001. Higher employee benefits and
other non-operating expenses ($26.7 million) were substantially offset by the
elimination in the second half of 2001 of coal trading activities ($16.3
million) and reduced facilities service business ($15.4 million). The decrease
in other operating costs for the nine-month period reflects several factors:
elimination of coal trading ($104.5 million), reduced facilities services
business ($39.4 million) and lower outage-related fossil plant expenditures
($39.7 million). Those reductions were more than offset by additional costs
related to nuclear refueling and unplanned outages ($59.5 million), employee
benefits and other non-operating expenses ($37.3 million) and several one-time
charges of $87.0 million in 2002, summarized in the table on page 17.
20
Charges for depreciation and amortization decreased $63.5 million in
the third quarter and $168.2 million in the first nine months of 2002 from the
corresponding periods last year. These decreases resulted from several factors:
shopping incentive deferrals and tax-related deferrals under the Ohio transition
plan, the elimination of depreciation associated with the planned sale of four
power plants and the cessation of goodwill amortization beginning January 1,
2002. FirstEnergy's goodwill amortization in the third quarter and year-to-date
periods of 2001 totaled $14.4 million and $42.4 million, respectively.
General taxes increased $9.8 million in the third quarter and $32.8
million in the first nine months of 2002 from the same periods in 2001. These
increases were principally due to additional property taxes. The successful
resolution of certain property tax issues in the second quarter of 2001 resulted
in a one-time benefit of $15 million in that quarter, representing a portion of
the increase in the nine-month period of 2002.
Net Interest Charges
Net interest charges increased $96.3 million in the third quarter and
$359.1 million in the first nine months of 2002, compared to the same periods of
2001. These increases included interest of $69.6 million in the third quarter
and $211.5 million in the first nine months of 2002 on $4 billion of long-term
debt issued by FirstEnergy in connection with the merger. Excluding the results
of the former GPU companies and the merger-related financing, net interest
charges decreased by $24.5 million in the third quarter and $34.3 million in the
first nine months of 2002 from the corresponding periods in 2001. Redemption and
refinancing activities completed in the first nine months of 2002 totaled $1.059
billion and $430.7 million, respectively, and are expected to result in
annualized savings of $96.9 million. FirstEnergy exchanged existing fixed-rate
payments on outstanding debt (principal amount of $993.5 million) for short-term
variable rate payments through interest rate swap transactions in June and July
2002. Net interest charges were reduced by $8.9 million in the third quarter of
2002 as a result of these swaps.
Cumulative Effect of Accounting Changes
Year-to-date earnings in 2002 and 2001 were affected by accounting
changes. In connection with the November 2001 merger, certain former GPU
international operations were identified as "assets pending sale." Subsequent to
the merger date, results of operations and incremental interest costs related to
these international subsidiaries were not included in FirstEnergy's Consolidated
Statement of Income. On February 6, 2002, discussions began with Aquila, Inc. on
modifying its initial offer for the acquisition of Avon Energy Partners
Holdings, which resulted in a change in accounting for this investment,
increasing net income in the first quarter of 2002 by $31.7 million. In the
first quarter of 2001, FirstEnergy adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," resulting in an $8.5 million after-tax
charge.
Results of Operations - Business Segments
- -----------------------------------------
FirstEnergy manages its business as two separate major business
segments - regulated services and competitive services. The regulated services
segment designs, constructs, operates and maintains FirstEnergy's regulated
domestic transmission and distribution systems. It also provides generation
services to regulated franchise customers who have not chosen an alternative
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, 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 6 to the consolidated financial statements.
Regulated Services
Net income increased to $382.9 million in the third quarter of 2002
and $853.7 million in the first nine months of 2002, compared to $246.1 million
and $527.9 million in the corresponding periods of 2001. Excluding results of
the former GPU companies, net income increased by $7.6 million to $253.7 million
in the third quarter and by $36.3 million to $564.1 million in the first nine
months of 2002. The factors contributing to the increase in pre-merger net
income are summarized in the following table:
21
Regulated Services
------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Revenues................................. $(105.8) $(365.9)
Expenses................................. (88.0) (359.4)
------- -------
Income Before Interest and Income Taxes.. (17.8) (6.5)
Net interest charges..................... (31.7) (82.9)
Income taxes............................. 6.3 40.1
------- -------
Net Income Increase...................... $ 7.6 $ 36.3
======= =======
Lower generation sales and additional transition plan incentive
credits combined to reduce revenues in the third quarter of 2002 from the same
period in 2001. In the first nine months of 2002, retail generation sales and
distribution throughput were both down, reflecting the combined impacts of tepid
economic conditions and shopping by Ohio customers for alternative energy
suppliers. Sales to FES were also lower, due to less available generation for
sale because of the unplanned outage at Davis-Besse.
Expenses were lower in the third quarter and first nine months of
2002 than the corresponding periods of 2001, primarily due to lower purchased
power and depreciation and amortization. Lower generation sales reduced the need
to purchase power from FES, which contributed to a $31.5 million expense
decrease in the third quarter and a $153.0 million decrease in the first nine
months of 2002, compared to the same periods last year. Depreciation and
amortization declined by $65.2 million in the third quarter and $179.2 million
in the first nine months of 2002, compared to the corresponding periods of 2001,
due to new deferred regulatory assets under the Ohio transition plan, the
elimination of depreciation associated with the planned sale of four power
plants and the cessation of goodwill amortization beginning January 1, 2002.
Other operating expenses also decreased by $47.4 million in the first nine
months of 2002, compared to the same period last year. The majority of the
decrease in other operating expenses resulted from reduced costs for jobbing and
contracting work combined with a decline in uncollectible accounts expense. Net
interest charges in the third quarter and year-to-date periods of 2002 decreased
by $31.7 million and $82.9 million, respectively, from the corresponding periods
of 2001, reflecting the impact of net debt and preferred stock redemptions and
refinancings.
Competitive Services
The competitive services segment incurred a net loss of $14.0 million
in the third quarter of 2002, compared to a net loss of $4.1 million in the same
period of 2001. For the first nine months of 2002, the net loss increased to
$67.3 million ($25.3 million net income excluding one-time charges) from $52.8
million in the first nine months of last year. Excluding results of the former
GPU companies, the net loss was $16.4 million in the third quarter and $71.6
million in the first nine months of 2002. The factors contributing to the
changes in pre-merger earnings are summarized in the following table:
Competitive Services
--------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Revenues.................................... $331.0 $166.5
Expenses.................................... 343.0 195.4
------ ------
Income Before Interest and Income Taxes..... (12.0) (28.9)
Net interest charges........................ 9.0 17.3
Income taxes................................ (8.6) (18.9)
Cumulative effect of a change in accounting. -- 8.5
------ ------
Net Income Decrease......................... $(12.4) $(18.8)
====== ======
The increased availability of power for the electric wholesale
market, due to additional internal generation and reduced kilowatt-hour sales to
affiliates, allowed FES to take advantage of additional wholesale market
opportunities in 2002 - increasing sales by $317.4 million in the third quarter
and $442.0 million in the first nine months of 2002, compared to the prior year.
FES retail electric sales revenue contributed $65.8 million to the increase in
the third quarter of 2002 and $65.0 million over the first nine months of 2002.
As a result, electricity sales to non-affiliates increased $383.2 million in the
22
third quarter and $507.0 million in the first nine months of 2002 from the same
periods last year. In the third quarter and first nine months of 2002, this
increase was partially offset by reduced sales to regulated affiliates
reflecting the impact of shopping by Ohio customers for alternative power
providers, lower natural gas revenues resulting from reduced volumes in the
third quarter and lower prices in the year-to-date period and less revenue from
the facilities services group, resulting in a net $331.0 million increase in the
third quarter and a $166.5 million increase in the year-to-date period.
Expenses increased in the third quarter and first nine months of
2002, compared to the same periods of 2001. Higher third quarter and
year-to-date expenses were primarily attributable to purchased power costs,
which increased $355.0 million and $278.8 million, respectively. Additional
kilowatt-hour sales and reduced nuclear generation, as a result of the extended
outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration), combined
to increase the volume of power purchased. Fuel costs increased in the third
quarter and first nine months of 2002 ($30.1 million and $90.2 million,
respectively), compared to the same periods last year, due to additional fossil
generation; higher unit costs for coal consumed also added to fuel costs in the
year-to-date period. Other operating expenses increased by $85.5 million in the
first nine months of 2002, compared to the same period last year. The majority
of the increase in other operating expenses resulted from additional nuclear
operating costs (offset in part by lower outage-related fossil plant
expenditures), severance costs and uncollectible account expense. Several
one-time charges increased other operating expenses by $71.1 million in the
first nine months of 2002 (see Expenses). Partially offsetting these expense
increases in the third quarter and first nine months of 2002 were lower expenses
from the facilities services group (principally resulting from reduced business
activity) and reduced gas costs due to decreased sales in the third quarter and
lower prices in the year-to-date period of 2002.
Capital Resources and Liquidity
- -------------------------------
FirstEnergy and its subsidiaries have continuing cash needs for
planned capital expenditures, maturing debt and preferred stock sinking fund
requirements. During the last quarter of 2002, capital requirements for property
additions and capital leases are expected to be about $342 million, including
$27 million for nuclear fuel. These requirements also include $28 million of
additional repair costs for the unplanned extended outage at the Davis-Besse
nuclear plant (see Davis-Besse Restoration). FirstEnergy has additional cash
requirements of approximately $58.7 million to meet sinking fund requirements
for preferred stock and maturing long-term debt during the remainder of 2002.
These cash requirements are expected to be satisfied from internal cash and
short-term credit arrangements.
As of September 30, 2002, FirstEnergy and its subsidiaries had about
$280.5 million of cash and temporary investments and $1.154 billion of
short-term indebtedness. Available borrowings included $290.0 million from
unused revolving lines of credit and $84 million from unused bank facilities at
the end of the third quarter 2002. On November 8, 2002, FirstEnergy replaced its
two maturing revolving lines of credit - $1.0 billion at FirstEnergy and $250
million at OE with a new FirstEnergy senior unsecured revolving credit facility
of $1.0 billion which can be used to facilitate optional long-term debt and
preferred stock redemptions to further reduce interest costs. Excluding property
already released under the applicable mortgage indentures related to the planned
sale of four power plants, OE, CEI, TE and Penn had the capability to issue $2.1
billion of additional first mortgage bonds (FMB) on the basis of property
additions and retired bonds, as of September 30, 2002. JCP&L, Met-Ed and Penelec
had the capability to issue $938.7 million of additional senior notes based upon
FMB collateral, as of September 30, 2002. Based upon applicable charter earnings
coverage tests through September 30, 2002, OE, Penn, TE and JCP&L could issue
$3.4 billion of preferred stock (assuming no additional debt was issued). CEI,
Met-Ed and Penelec have no restrictions on the issuance of preferred stock.
Off-balance sheet debt equivalents for sale and lease back transactions of
generating units entered into in 1987 and accounts receivable factoring totaled
$1.673 billion as of September 30, 2002.
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 ratings contingent collateralization provisions.
As of September 30, 2002, outstanding guarantees and other assurances
totaled $880.9 million as follows:
23
Guarantees and Other Assurances
-------------------------------
(In millions)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts....... $ 614.8
Financings (1)............................ 217.0
-------
831.8
Surety Bonds................................ 25.8
Rating-Contingent Collateralization (2)..... 23.3
-------
Total Guarantees and Other Assurances..... $ 880.9
=======
(1) Includes parental guarantees of subsidiary debt and
lease financing including FirstEnergy letters of
credit supporting subsidiary debt.
(2) Estimated net liability under contracts subject to
rating-contingent collateralization provisions.
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 assets of FirstEnergy.
The likelihood that such parental guarantees will increase amounts otherwise
paid by FirstEnergy to meet its obligations incurred in connection with ongoing
energy and energy-related activities is remote.
Most of FirstEnergy's surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees 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 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. Requirements of these provisions vary and typically require more
than one rating reduction to below investment grade by Standard & Poor's or
Moody's Investors Service to trigger additional collateralization by
FirstEnergy.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of FirstEnergy's full-time employees are eligible to
participate in these plans. In accordance with the provisions of the Employment
Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded
status of its pension plans annually to determine if additional funding is
necessary. FirstEnergy has pre-funded a portion of the future liabilities
related to its OPEB plans. Under the terms of its postretirement benefit plans,
FirstEnergy reserves the right to change, modify or terminate the plans. Its
pension plan funding policy is to contribute annually an amount that is in
accordance with the provisions of ERISA - no contributions have been required
since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate capital
resources through cash generated from operations and through existing lines of
credit to support necessary funding requirements based on anticipated plan
performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, it would be
required to record an after-tax charge to equity (other comprehensive income) of
approximately $328 million in the fourth quarter of 2002 to recognize its
additional minimum pension liability of $637 million. The amount recorded will
depend upon the financial markets and interest rates in the remainder of 2002.
In addition, pension and other postretirement costs could increase by as much as
$165 million in 2003 based on the reduction of plan assets through October
31, 2002, due to adverse equity market conditions, lower rate of return
assumptions and the amortization of unrecognized losses, as well as higher
health care trend rates for OPEB (see Significant Accounting Policies - Pension
and Other Postretirement Benefits Accounting).
24
Market Risk Information
- -----------------------
FirstEnergy uses various market sensitive instruments, including
derivative contracts, primarily to manage the risk of price, interest rate and
foreign currency fluctuations. 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.
Commodity Price Risk
FirstEnergy is exposed to market risk primarily due to fluctuations
in electricity, natural gas and coal prices. 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 much lesser
extent, for trading purposes. Most of FirstEnergy's 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:
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
--------------------------- ---------------------------
Non-Hedge Hedge Total Non-Hedge Hedge Total
--------- ----- ----- --------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative
Contracts
Outstanding net asset at beginning of period........... $14.8 $(12.8) $ 2.0 $ 9.9 $(76.2) $(66.3)
New contract value when entered........................ -- -- -- -- 2.1 2.1
Additions/Increase in value of existing contracts...... 13.7 20.0 33.7 40.9 52.8 93.7
Change in techniques/assumptions....................... -- -- -- (20.1) -- (20.1)
Settled contracts...................................... 7.9 1.8 9.7 5.7 30.3 36.0
---------------------------- ------------------------------
Outstanding net asset at end of period (1)............. 36.4 9.0 45.4 36.4 9.0 45.4
---------------------------- ------------------------------
Non-commodity net assets at end of period:
Interest Rate Swaps (2)............................. -- 37.3 37.3 -- 37.3 37.3
---------------------------- ------------------------------
Net Assets - Derivatives Contracts (3)................. $36.4 $ 46.3 $82.7 $ 36.4 $ 46.3 $ 82.7
============================ ==============================
Impact of Changes in Commodity Derivative Contracts(4)
Income Statement Effects (Pre-Tax)..................... $17.8 $ -- $17.8 $ 4.7 $ -- $ 4.7
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $ -- $ 21.8 $21.8 $ -- $ 83.1 $ 83.1
Regulatory Liability................................ $ 3.8 $ -- $ 3.8 $ 21.8 $ -- $ 21.8
Derivatives included on the Consolidated Balance Sheet as of September 30, 2002:
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Current-
Other Assets................ $ 20.4 $ 7.4 $ 27.8
Other Liabilities........... (20.8) (12.1) (32.9)
Non-Current-
Other Deferred Charges...... 40.7 52.9 93.6
Other Deferred Credits...... (3.9) (1.9) (5.8)
------ ------ ------
Net assets................ $ 36.4 $ 46.3 $ 82.7
====== ====== ======
(1) Includes $26 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Interest rate swaps are treated as fair value hedges. Changes in derivative
values are offset by changes in the hedged debts' premium or discount.
(3) Excludes $0.6 million of derivative contract fair value decrease, as of
September 30, 2002, representing FirstEnergy's 50% share of Great Lakes
Energy Partners, LLC.
(4) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
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, FirstEnergy relies on model-based
information. The model provides estimates of future regional prices for
electricity and an estimate of related price volatility. FirstEnergy utilizes
these results in developing 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:
25
Source of Information - Fair Value by Contract Year
- ---------------------------------------------------
2002(1) 2003 2004 Thereafter Total
---- ---- ---- ---------- -----
(In millions)
Prices actively quoted...... $(0.9) $15.7 $(1.1) $(0.6) $13.1
Prices based on models(2)... -- -- -- 32.3 32.3
------------------------------------------------
Total................... $(0.9) $15.7 $(1.1) $31.7 $45.4
=================================================
(1) For the last quarter of 2002.
(2) Includes $26 million from an embedded option that is offset by a regulatory
liability and does not affect earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to
the market risk of its commodity positions. A hypothetical 10% adverse shift in
quoted market prices in the near term on both FirstEnergy's trading and
nontrading derivative instruments would not have had a material effect on its
consolidated financial position or cash flows as of September 30, 2002.
FirstEnergy estimates that if energy commodity prices experienced an adverse 10
percent change, net income for the next twelve months would decrease by
approximately $6.4 million.
State Regulatory Matters
- ------------------------
Ohio
The transition cost portion of FirstEnergy's Ohio EUOC rates provides
for recovery of certain amounts not otherwise recoverable in a competitive
generation market (such as regulatory assets). Transition costs are paid by all
customers whether or not they choose an alternative supplier. Under the
PUCO-approved transition plan, FirstEnergy assumed the risk of not recovering up
to $500 million of transition costs if the rate of customers (excluding
contracts and full-service accounts) switching their service from OE, CEI and TE
had not reached 20% for any consecutive twelve-month period by December 31, 2005
- - the end of the market development period. Based on actual shopping levels
attained through October 2002, FirstEnergy has achieved all of its required 20%
customer shopping goals, and there is therefore no longer risk of regulatory
action reducing the recoverable transition costs.
New Jersey
On August 1, 2002, FirstEnergy submitted two rate filings for JCP&L
with the New Jersey Board of Public Utilities (NJBPU). The first filing is a
request to increase base electric rates by $98 million annually, an average of
5%. The second filing is a request to recover deferred costs associated with
mandated purchase-power contracts with non-utility generators and providing
Basic Generation Service to customers in excess of the state's generation rate
cap. As of September 30, 2002, the accumulated deferred cost balance totaled
approximately $482 million. The deferral filing would result in an additional
2.8% increase in rates, assuming the use of securitization. The securitization
methodology is similar to the Oyster Creek securitization completed in May 2002.
The NJBPU has directed the Office of Administrative Law to have its
Administrative Law Judge issue a recommended decision by May 1, 2003; the Judge
has indicated she would request an extension. The rates established in this
proceeding will become effective August 1, 2003.
Pennsylvania
Several parties had filed Petitions for Review in June and July 2001
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders
which approved the FirstEnergy/GPU merger and provided Met-Ed and Penelec rate
relief. 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 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 Supreme Court of Pennsylvania. In
September 2002, Met-Ed and Penelec established reserves for their PLR deferred
energy costs which aggregated $287.1 million (Met-Ed $143.2 million and Penelec
$143.9 million). The reserves reflect 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) for the deferred costs incurred subsequent to the
merger - $30.7 million ($17.9 million net of tax) by Met-Ed and $25.1 million
($14.7 million net of tax) by Penelec. The reserve for the remaining $231.3
million (Met-Ed - $112.5 million and Penelec - $118.8 million) of deferred costs
increased goodwill by an aggregate net of tax amount of $135.3 million
(Met-Ed-$65.8 million and Penelec-$69.5 million).
26
Sale of Power Plants
- --------------------
In November 2001, FirstEnergy announced an agreement to sell four of
its older coal-fired power plants located along Lake Erie in Ohio to NRG (see
Note 3). 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 is reserving 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. FirstEnergy is pursuing opportunities with other
parties who have expressed interest in purchasing the plants. It expects to
conclude a bid process with interested parties in the fourth quarter of 2002,
with the objective of executing an acceptable sales agreement by year-end. If
FirstEnergy has not executed a sales agreement by year-end, it would need to
reflect up to $58 million of unrecognized depreciation and other transaction
costs.
Emdersa Divestiture
- -------------------
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 has determined that it is not probable that the
subsequent economic conditions in Argentina have eroded the fair value recorded
for Emdersa; as a result, an impairment writedown of this investment is not
warranted as of September 30, 2002. FirstEnergy continues to assess the
potential impact of these and other related events on the realizability of the
value recorded for Emdersa. FirstEnergy continues to pursue divesting Emdersa
and, in accordance with EITF Issue No. 87-11, has classified its assets and
liabilities in the Consolidated Balance Sheet as "Assets Pending Sale" and
"Liabilities Related to Assets Pending Sale." FirstEnergy believes it is
probable that a completed sale or a definitive agreement to sell its interest in
Emdersa could be achieved in 2002. Potential investors recently retained a
financial advisor to assist in the due diligence process and FirstEnergy
believes it is probable that preliminary negotiations with those investors will
be completed in 2002. If FirstEnergy does not sell Emdersa - an Argentinean
distribution company that FirstEnergy acquired through its merger with GPU - or
reach a definite agreement to do so in 2002, FirstEnergy could no longer include
Emdersa as an asset pending sale on its consolidated balance sheet. As a result,
FirstEnergy would include any income or loss generated by Emdersa after that
day, or the date that a sale is considered not probable, in its consolidated
statement of income. In addition, FirstEnergy would recognize a one-time,
non-cash cumulative effect of a change in accounting to reflect Emdersa's
cumulative results from November 7, 2001 - the effective date of the merger with
GPU - through the date that it becomes probable that a definitive agreement to
sell would not be achieved in 2002. Based on results through September 30, 2002,
the amount of such a one-time, after-tax charge would be approximately $94
million, or $0.32 per share.
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 FirstEnergy 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. FirstEnergy
expects to complete refurbishment and installation of the replacement reactor
head as well as any other work related to restart of the plant early in 2003.
The NRC must authorize restart of the plant following its formal inspection
process before the unit can be returned to service.
The estimated costs (capital and expense) associated with the
extended Davis-Besse outage in 2002 and 2003 are:
27
Costs of Davis-Besse Extended Outage
- ------------------------------------
Expenditure Range
-----------------
(In millions)
2002
- ----
Replace reactor vessel head (principally capital expenditures). $55 - $75
Primarily operating expenses (pre-tax):
Additional maintenance (including acceleration of programs).... $115 - $135
Replacement power through September 2002....................... $85
Replacement power for October through December 2002............ $30 - $45
2003
- ----
Additional work to enhance reliability and performance......... $50
The replacement power costs for 2003 are estimated to be $10-$15
million per month. FirstEnergy has fully hedged its on-peak replacement energy
supply for Davis-Besse through the end of 2002 and has completed some hedging in
2003 as well.
Provider of Last Resort
- -----------------------
FirstEnergy continues to enter into power contracts to cover its
"provider of last resort" obligations for the 2003-2005 period. Market
conditions are currently favorable, therefore minimizing FirstEnergy's exposure
to the commodity market. FirstEnergy is now nearly 100% hedged for 2003, 95%
hedged for 2004 and 88% hedged for 2005 projected obligations.
Environmental Matters
- ---------------------
The EUOCs 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 September 30, 2002, based on estimates of the
total costs of cleanup, the EUOCs' 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 a non-bypassable societal benefits charge. The EUOCs have total accrued
liabilities aggregating approximately $57.9 million as of September 30, 2002.
FirstEnergy does not believe environmental remediation costs will have a
material adverse effect on its financial condition, cash flows or results of
operations.
Significant Accounting Policies
- -------------------------------
FirstEnergy prepares its 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
FirstEnergy's 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. FirstEnergy's 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
preliminary purchase price allocations for the GPU acquisition are subject to
adjustment in 2002 when finalized.
Regulatory Accounting
FirstEnergy's 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 FirstEnergy is 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 FirstEnergy operates, a significant amount of
regulatory assets have been recorded - $8.4 billion as of September 30, 2002.
FirstEnergy regularly reviews these assets to
28
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. FirstEnergy continually monitors its derivative contracts to
determine if its activities, expectations, intentions, assumptions and estimates
remain valid. As part of its normal operations, FirstEnergy enters into
significant commodity contracts, as well as interest rate and currency swaps,
which increase the impact of derivative accounting judgments.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
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.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension benefits.
Corporate bond yields, as well as interest rates in general, have declined in
the first nine months of 2002, which could affect FirstEnergy's discount rate as
of December 31, 2002. If the discount rate is reduced below the current assumed
rate, liabilities and pension and OPEB costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and
13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio.
29
If a lower rate of return were to be assumed in 2003, FirstEnergy's reported
pension costs would increase. While OPEB plan assets have also been affected by
sharp declines in the equity market, the impact is moderated due to smaller
asset balances. However, medical cost trends have significantly increased and
could affect future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholders' equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods to
the extent the fair value of trust assets would exceed the accumulated benefit
obligation. The amount of pension liability to be recorded as of December 31,
2002, will depend upon the discount rate and asset returns experienced in 2002
(and any resulting change in FirstEnergy's assumptions).
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its
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, FirstEnergy recognizes a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
Goodwill
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, "Goodwill
and Other Intangible Assets," FirstEnergy evaluates its goodwill for impairment
at least annually and would make such an evaluation more frequently if
indicators of impairment should arise. The accounting standard requires that 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 FirstEnergy 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. FirstEnergy's annual
review was completed in the third quarter of 2002. The results of that review
indicated no impairment of goodwill. As of September 30, 2002, FirstEnergy had
$5.8 billion of goodwill that primarily relates to its regulated services
segment.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the Financial Accounting Standards Board in July 2002,
requires the recognition of costs associated with exit or disposal activities at
the time they are incurred rather than when management commits to a plan of exit
or disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." This new standard will be 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.
On October 25, 2002, the Emerging Issues Task Force (EITF) reached a
consensus in 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," to rescind EITF Issue No. 98-10 (and related
interpretative guidance). Rescinding EITF No. 98-10 eliminates mark-to-market
accounting for energy trading contracts that are not derivatives under SFAS 133.
This guidance will be effective for all new contracts entered into after October
25, 2002 and the impact of its initial application will be reported as a change
in accounting principle. Additionally, the EITF concluded that gains and losses
on all derivative instruments under SFAS 133 that are held for trading purposes
should be netted against related purchases or sales in the income statement.
This new presentation requirement will be effective for periods beginning after
December 15, 2002. FirstEnergy is not impacted by the rescission of EITF 98-10
and does not anticipate a material effect from the net presentation requirement.
30
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- ------------------------
2002 2001 2002 2001
-------- -------- ---------- ----------
(In thousands)
OPERATING REVENUES........................................ $813,296 $815,695 $2,265,645 $2,343,510
-------- -------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 15,649 12,484 45,068 40,038
Purchased power........................................ 243,475 271,201 698,126 815,413
Nuclear operating costs................................ 79,388 117,918 255,322 287,150
Other operating costs.................................. 94,820 80,611 252,928 241,283
-------- -------- ---------- ----------
Total operation and maintenance expenses............. 433,332 482,214 1,251,444 1,383,884
Provision for depreciation and amortization............ 82,691 104,302 266,342 325,463
General taxes.......................................... 47,254 43,604 135,154 114,691
Income taxes........................................... 95,517 63,087 222,535 170,228
-------- -------- ---------- ----------
Total operating expenses and taxes................... 658,794 693,207 1,875,475 1,994,266
-------- -------- ---------- ----------
OPERATING INCOME.......................................... 154,502 122,488 390,170 349,244
OTHER INCOME.............................................. 14,212 18,695 29,811 48,881
-------- -------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES........................ 168,714 141,183 419,981 398,125
-------- -------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................. 29,548 36,978 92,933 115,892
Allowance for borrowed funds used during construction
and capitalized interest............................. (1,018) (573) (2,522) (1,879)
Other interest expense................................. 2,889 4,963 10,837 17,681
Subsidiaries' preferred stock dividend requirements.... 2,276 3,626 9,528 10,878
-------- -------- ---------- ----------
Net interest charges................................. 33,695 44,994 110,776 142,572
-------- -------- ---------- ----------
NET INCOME................................................ 135,019 96,189 309,205 255,553
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 658 2,702 5,851 8,106
-------- -------- ---------- ----------
EARNINGS ON COMMON STOCK.................................. $134,361 $ 93,487 $ 303,354 $ 247,447
======== ======== ========== ==========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
31
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- --------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $4,964,114 $4,979,807
Less-Accumulated provision for depreciation............................... 2,496,400 2,461,972
---------- ----------
2,467,714 2,517,835
---------- ----------
Construction work in progress-
Electric plant.......................................................... 116,172 87,061
Nuclear fuel............................................................ 3,146 11,822
---------- ----------
119,318 98,883
---------- ----------
2,587,032 2,616,718
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust........................................................ 415,664 429,040
Letter of credit collateralization........................................ 277,763 277,763
Nuclear plant decommissioning trusts...................................... 285,835 277,337
Long-term notes receivable from associated companies...................... 504,133 505,028
Other..................................................................... 292,060 303,409
---------- ----------
1,775,455 1,792,577
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 45,785 4,588
Receivables-
Customers (less accumulated provisions of $5,349,000 and $4,522,000,
respectively, for uncollectible accounts)............................. 344,795 311,744
Associated companies.................................................... 481,047 523,884
Other (less accumulated provisions of $1,000,000 for uncollectible
accounts at both dates)............................................... 36,946 41,611
Notes receivable from associated companies................................ 409,607 108,593
Materials and supplies, at average cost-
Owned................................................................... 57,778 53,900
Under consignment....................................................... 18,566 13,945
Other..................................................................... 17,477 50,541
---------- ----------
1,412,001 1,108,806
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 2,070,556 2,234,227
Other..................................................................... 162,533 163,625
---------- ----------
2,233,089 2,397,852
---------- ----------
$8,007,577 $7,915,953
========== ==========
32
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- --------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
100 shares outstanding................................................ $2,098,729 $2,098,729
Retained earnings....................................................... 753,726 572,272
---------- ----------
Total common stockholder's equity................................... 2,852,455 2,671,001
Preferred stock not subject to mandatory redemption....................... 60,965 160,965
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption..................................... 39,105 39,105
Subject to mandatory redemption......................................... 14,250 14,250
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely Company
subordinated debentures................................................. -- 120,000
Long-term debt............................................................ 1,265,033 1,614,996
---------- ----------
4,231,808 4,620,317
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 532,089 576,962
Short-term borrowings-
Associated companies.................................................... 401,084 26,076
Other................................................................... 166,716 219,750
Accounts payable-
Associated companies.................................................... 122,306 110,784
Other................................................................... 7,526 19,819
Accrued taxes............................................................. 481,393 258,831
Accrued interest.......................................................... 33,016 33,053
Other..................................................................... 99,433 63,140
---------- ----------
1,843,563 1,308,415
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 1,101,118 1,175,395
Accumulated deferred investment tax credits............................... 89,647 99,193
Nuclear plant decommissioning costs....................................... 284,997 276,500
Other postretirement benefits............................................. 172,737 166,594
Other..................................................................... 283,707 269,539
---------- ----------
1,932,206 1,987,221
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$8,007,577 $7,915,953
========== ==========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.
33
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $135,019 $ 96,189 $309,205 $ 255,553
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation and amortization........ 82,691 104,302 266,342 325,463
Nuclear fuel and lease amortization................ 12,389 10,125 35,924 33,802
Deferred income taxes, net......................... (9,782) (9,182) (31,838) (51,744)
Investment tax credits, net........................ (3,751) (3,331) (11,286) (10,025)
Receivables........................................ (18,352) (26,425) 14,451 (221,220)
Materials and supplies............................. (3,699) 5,815 (8,499) 59,875
Accounts payable................................... 18,690 (4,888) (771) (57,572)
Accrued taxes...................................... 16,302 31,296 222,562 49,507
Other.............................................. 44,883 48,727 39,240 2,100
-------- -------- -------- ---------
Net cash provided from operating activities...... 274,390 252,628 835,330 385,739
-------- -------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 14,500 6,619 14,500 256,161
Short-term borrowings, net........................... 348,132 80,346 321,974 64,899
Redemptions and Repayments-
Preferred stock...................................... 220,000 5,000 220,000 5,000
Long-term debt....................................... 182,595 178,039 411,336 215,749
Dividend Payments-
Common stock......................................... 20,700 100,000 121,900 137,300
Preferred stock...................................... 658 2,668 5,851 8,072
-------- -------- -------- ---------
Net cash used for financing activities........... 61,321 198,742 422,613 45,061
-------- -------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... 32,130 49,908 87,851 90,914
Loans to associated companies.......................... 165,340 71,900 300,665 383,729
Loan payments from associated companies................ -- -- (546) (506)
Sale of assets to associated companies................. -- -- -- (154,596)
Other.................................................. (6,047) 13,199 (16,450) 7,153
-------- -------- -------- ---------
Net cash used for investing activities........... 191,423 135,007 371,520 326,694
-------- -------- -------- ---------
Net increase (decrease) in cash and cash equivalents...... 21,646 (81,121) 41,197 13,984
Cash and cash equivalents at beginning of period.......... 24,139 113,374 4,588 18,269
-------- -------- -------- ---------
Cash and cash equivalents at end of period................ $ 45,785 $ 32,253 $ 45,785 $ 32,253
======== ======== ======== =========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
34
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison
Company and its subsidiaries as of September 30, 2002, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 30, 2002. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
35
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE
and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and
Pennsylvania, providing regulated electric distribution services. OE and Penn
(OE Companies) also provide generation services to those customers electing to
retain them as their power supplier. The OE Companies provide power directly to
wholesale customers under previously negotiated contracts, as well as to
alternative energy suppliers under OE's transition plan. The OE Companies have
unbundled the price of electricity into its component elements - including
generation, transmission, distribution and transition charges. Power supply
requirements of the OE Companies are provided by FES - an affiliated company.
Results of Operations
- ---------------------
Operating revenues decreased $2.4 million or 0.3% in the third
quarter of 2002 and $77.9 million or 3.3% in the first nine months of 2002, as
compared to the corresponding periods of 2001. Changes in operating revenues
reflect the combined effects of a weak but recovering economy, shopping by Ohio
customers for alternative energy providers, changes in revenues from wholesale
customers and weather. Retail kilowatt-hour sales declined by 6.2% in the third
quarter and 10.2% in the first nine months of 2002, compared to the same periods
of 2001, with declines in all customer sectors (residential, commercial and
industrial), resulting in a $16.0 million and a $56.9 million reduction in
generation sales revenue, respectively. OE's lower generation kilowatt-hour
sales in both periods resulted principally from customer choice in Ohio. Sales
of electric generation by alternative suppliers as a percent of total sales
delivered in the OE Companies' franchise area increased to 23.6% in the third
quarter of 2002 from 16.4% in the same period last year. During the first nine
months of 2002, OE's share of electric generation sales in its franchise areas
decreased by 8.7 percentage points, compared to the same period of 2001.
Distribution deliveries increased 2.6% in the third quarter of 2002,
which increased revenues from electricity throughput by $22.4 million, compared
with the third quarter of 2001. The third quarter of 2002 benefited from a
slight improvement in economic activity and unusually hot summer weather.
Despite a stronger third quarter performance, distribution deliveries were lower
in the first nine months of 2002, compared to the same period last year,
declining by 0.4% primarily due to the weaker economic environment earlier in
the year. Distribution revenues increased $15.4 million in the year-to-date
period as higher residential revenues were partially offset by lower industrial
revenues.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, further reduced operating revenues in
the third quarter and first nine months of 2002, compared to the corresponding
periods of 2001 - reducing comparable revenues by $9.7 million and $26.3
million, respectively. These revenue reductions are deferred for future recovery
under OE's transition plan and do not materially affect current period earnings.
Sales revenues from wholesale customers increased by $4.6 million in
the third quarter of 2002, compared to the third quarter of 2001, as a result of
increased kilowatt-hour sales to nonaffiliated wholesale customers and to FES.
Sales revenues from wholesale customers were $5.6 million lower in the
nine-month period of 2002, compared to the same period last year. Increased
revenues from kilowatt-hour sales to nonaffiliated wholesale customers were more
than offset by reduced revenues from FES.
The sources of changes in operating revenues during the third quarter
and first nine months of 2002, compared with the corresponding periods of 2001,
are summarized in the following table:
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Retail:
Generation sales.................... $(16.0) $(56.9)
Distribution deliveries............. 22.4 15.4
Increased shopping incentives....... (9.7) (26.3)
------ ------
Total Retail........................ (3.3) (67.8)
Wholesale............................. 4.6 (5.6)
Other................................. (3.7) (4.5)
------ ------
Net Decrease in Operating Revenue..... $ (2.4) $(77.9)
====== ======
36
Operating Expenses and Taxes
Total operating expenses and taxes declined $34.4 million and $118.8
million in the third quarter and the first nine months of 2002, respectively,
compared to the corresponding periods of 2001. Purchased power costs decreased
$27.7 million in the third quarter and $117.3 million in the first nine months
of 2002, compared to the same periods last year, due to lower unit costs.
Reduced volume requirements supporting lower generation kilowatt-hour sales also
contributed to decreased purchased power costs for the first nine months of
2002, compared to the same period in 2001. Nuclear operating costs decreased
$38.5 million in the third quarter of 2002, compared to the corresponding period
last year, primarily due to the absence of a refueling outage in the third
quarter of 2002; Beaver Valley Unit 1 (100% owned) experienced a refueling
outage in the third quarter of 2001. In the first nine months of 2002, nuclear
operating costs decreased by $31.8 million from the same period last year.
Additional nuclear operating costs related to the first quarter 2002 refueling
outage at Beaver Valley Unit 2 (55.62% owned) that exceeded refueling outage
costs for the Perry Plant (35.24% owned) in the same period of 2001 were more
than offset by the absence of a nuclear refueling outage in the third quarter of
2002. Other operating costs increased $14.2 million and $11.6 million in the
third quarter and first nine months of 2002, respectively, compared to the same
periods last year, primarily due to employee severance costs and higher
distribution expenses in the third quarter of 2002.
Charges for depreciation and amortization decreased by $21.6 million
in the third quarter and $59.1 million in the first nine months of 2002,
compared to the same periods last year. These decreases reflect higher shopping
incentive deferrals and tax-related deferrals under OE's transition plan in
2002.
General taxes increased by $3.7 million in the third quarter and
$20.5 million in the first nine months of 2002 from the same periods in 2001.
Increased property taxes and a higher gross receipts tax rate for 2002
contributed to the increase in general taxes for both periods. The successful
resolution of certain property tax issues in the second quarter of 2001 provided
a one-time benefit of $15 million in that year.
Other Income
Other income decreased $4.5 million in the third quarter and $19.1
million in the first nine months of 2002 from the corresponding periods of 2001.
Reduced interest income was the principal factor in the third quarter decrease.
A large part of the reduction for the year-to-date period resulted from a first
quarter 2002 adjustment related to OE's low income housing investments.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $11.3
million in the third quarter and $31.8 million in the first nine months of 2002,
compared to the same periods last year, primarily due to redemption and
refinancing activities. During the first nine months of 2002, maturing debt and
preferred stock redemption and refinancing transactions totaled $407.6 million
and $134.5 million, respectively, and will result in annualized savings of $43.3
million.
Capital Resources and Liquidity
- -------------------------------
The OE Companies have continuing cash requirements for planned
capital expenditures and maturing debt. During the fourth quarter of 2002,
capital requirements for property additions and capital leases are expected to
be about $54 million, including $17 million for nuclear fuel. The OE Companies
also have sinking fund requirements for preferred stock and maturing long-term
debt of $15.4 million. These requirements are expected to be satisfied from
internal cash and/or short-term credit arrangements.
As of September 30, 2002, the OE Companies had about $455.4 million
of cash and temporary investments and $567.8 million of short-term indebtedness.
Their available borrowing capability included $250.0 million from unused
revolving lines of credit and $34 million from unused bank facilities at the end
of the third quarter of 2002. On November 8, 2002, FirstEnergy replaced two
maturing revolving lines of credit totaling $1.25 billion, including $250
million at OE, with a new FirstEnergy senior unsecured revolving credit facility
of $1.0 billion. As of September 30, 2002, the OE Companies had the capability
to issue up to $1.7 billion of additional first mortgage bonds on the basis of
property additions and retired bonds. Under the earnings coverage tests
contained in the OE Companies' charters, $3.1 billion of preferred stock
(assuming no additional debt was issued) could be issued based on earnings
through the third quarter of 2002. Off-balance sheet debt equivalents for sale
and leaseback transactions of generating units entered into in 1987 totaled $703
million as of September 30, 2002.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of the OE Companies full-time employees are eligible to
participate in these plans. In accordance with the provisions of the Employment
Retirement Income Security Act of 1974 (ERISA),
37
FirstEnergy reviews the funded status of its pension plans annually to determine
if additional funding is necessary. FirstEnergy has pre-funded a portion of the
future liabilities related to its OPEB plans. Under the terms of its
postretirement benefit plans, FirstEnergy reserves the right to change, modify
or terminate the plans. Its pension plan funding policy is to contribute
annually an amount that is in accordance with the provisions of ERISA - no
contributions have been required since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate capital
resources through cash generated from operations and through existing lines of
credit to support necessary funding requirements based on anticipated plan
performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, the OE
Companies would be required to record an after-tax charge to equity (other
comprehensive income) of approximately $136 million in the fourth quarter of
2002 to recognize their additional minimum pension liability of $242 million.
The amount recorded will depend upon the financial markets and interest rates in
the remainder of 2002. In addition, pension and other postretirement costs could
increase by as much as $11 million in 2003 based on the reduction of plan assets
through October 31, 2002, due to adverse equity market conditions, lower rate of
return assumptions and the amortization of unrecognized losses, as well as
higher health care trend rates for OPEB (see Significant Accounting Policies -
Pension and Other Postretirement Benefits Accounting).
State Regulatory Matters
- ------------------------
The transition cost portion of the OE Companies' rates provides for
recovery of certain amounts not otherwise recoverable in a competitive
generation market (such as regulatory assets). Transition costs are paid by all
customers whether or not they choose an alternative supplier. Under the
PUCO-approved transition plan, OE assumed the risk of not recovering up to $250
million of transition costs if the rate of customers (excluding contracts and
full-service accounts) switching their service from OE had not reached 20% for
any consecutive twelve-month period by December 31, 2005 - the end of the market
development period. Based on actual shopping levels through October 2002, OE has
achieved its required 20% customer shopping and there is no longer risk of
regulatory action reducing the recoverable transition costs.
Significant Accounting Policies
- -------------------------------
OE prepares its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect the OE Companies' financial results. All of the OE
Companies' 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. The OE Companies' more
significant accounting policies are described below.
Regulatory Accounting
The OE Companies are subject to regulation that sets the prices
(rates) they are permitted to charge their customers based on the costs that
regulatory agencies determine the OE Companies are permitted to recover. At
times, regulators permit the future recovery through rates of costs that would
be currently charged to expense by an unregulated company. This rate-making
process results in the recording of regulatory assets based on anticipated
future cash inflows.As a result of the changing regulatory framework in Ohio and
Pennsylvania, a significant amount of regulatory assets have been recorded -
$2.1 billion as of September 30, 2002. OE regularly reviews 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.
38
Revenue Recognition
The OE Companies follow the accrual method of accounting for
revenues, recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," the OE Companies periodically evaluate their
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
impairment must be recognized in the financial statements. If impairment other
than of a temporary nature has occurred, the OE Companies recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
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.
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced below the current assumed rate, liabilities and
pension and OPEB costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and
13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, the OE Companies reported pension costs
would increase. While OPEB plan assets have also been affected by sharp declines
in the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased and could affect
future postretirement benefit costs.
39
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholder's equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods to
the extent the fair value of trust assets would exceed the accumulated benefit
obligation. The amount of pension liability to be recorded as of December 31,
2002, will depend upon the discount rate and asset returns experienced in 2002
(and any resulting change in FirstEnergy's assumptions).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time they are incurred rather
than when management commits to a plan of exit or disposal. It also requires the
use of fair value for the measurement of such liabilities. The new standard
supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This
new standard will be 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.
40
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ------------------------
2002 2001 2002 2001
-------- -------- ---------- ----------
(In thousands)
OPERATING REVENUES........................................ $538,879 $603,332 $1,426,730 $1,618,515
-------- -------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 15,809 19,685 48,167 54,438
Purchased power........................................ 140,357 135,156 398,251 543,251
Nuclear operating costs................................ 56,893 27,236 167,095 105,865
Other operating costs.................................. 80,786 72,923 215,986 223,622
-------- -------- ---------- ----------
Total operation and maintenance expenses........... 293,845 255,000 829,499 927,176
Provision for depreciation and amortization............ 17,846 51,705 74,650 161,433
General taxes.......................................... 40,771 37,261 116,010 109,211
Income taxes........................................... 57,925 86,087 110,003 115,381
-------- -------- ---------- ----------
Total operating expenses and taxes................. 410,387 430,053 1,130,162 1,313,201
-------- -------- ---------- ----------
OPERATING INCOME.......................................... 128,492 173,279 296,568 305,314
OTHER INCOME.............................................. 5,562 3,991 14,159 9,549
-------- -------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES........................ 134,054 177,270 310,727 314,863
-------- -------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................. 44,441 47,717 136,808 144,319
Allowance for borrowed funds used during construction.. (1,155) (594) (2,651) (1,667)
Other interest expense (credit)........................ 1,727 1,257 1,073 (818)
Subsidiaries' preferred stock dividend requirements.... 2,250 -- 6,650 --
-------- -------- ---------- ----------
Net interest charges............................... 47,263 48,380 141,880 141,834
-------- -------- ---------- ----------
NET INCOME................................................ 86,791 128,890 168,847 173,029
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 3,149 6,316 14,459 19,438
-------- -------- ---------- ----------
EARNINGS ON COMMON STOCK.................................. $ 83,642 $122,574 $ 154,388 $ 153,591
======== ======== ========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of
these statements.
41
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- --------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $4,090,597 $4,071,134
Less-Accumulated provision for depreciation............................... 1,797,438 1,725,727
---------- ----------
2,293,159 2,345,407
---------- ----------
Construction work in progress-
Electric plant.......................................................... 119,454 66,266
Nuclear fuel............................................................ 32,055 21,712
---------- ----------
151,509 87,978
---------- ----------
2,444,668 2,433,385
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 437,824 475,543
Nuclear plant decommissioning trusts...................................... 219,340 211,605
Long-term notes receivable from associated companies...................... 103,091 103,425
Other..................................................................... 20,856 24,611
---------- ----------
781,111 815,184
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 8,206 296
Receivables-
Customers............................................................... 15,803 17,706
Associated companies.................................................... 57,704 75,113
Other (less accumulated provisions of $1,015,000 for
uncollectible accounts at both dates)................................. 147,411 99,716
Notes receivable from associated companies................................ 544 415
Materials and supplies, at average cost-
Owned................................................................... 18,319 20,230
Under consignment....................................................... 35,436 28,533
Other..................................................................... 3,489 31,634
---------- ----------
286,912 273,643
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 921,557 874,488
Goodwill.................................................................. 1,370,639 1,370,639
Other..................................................................... 97,833 88,767
---------- ----------
2,390,029 2,333,894
---------- ----------
$5,902,720 $5,856,106
========== ==========
42
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- --------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding......................................... $ 981,962 $ 931,962
Retained earnings....................................................... 304,369 150,183
---------- ----------
Total common stockholder's equity................................... 1,286,331 1,082,145
Preferred stock-
Not subject to mandatory redemption..................................... 96,404 141,475
Subject to mandatory redemption......................................... 5,049 6,288
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000
Long-term debt............................................................ 2,035,187 2,156,322
---------- ----------
3,522,971 3,486,230
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 316,806 526,630
Accounts payable-
Associated companies.................................................... 104,949 81,463
Other................................................................... 10,084 30,332
Notes payable to associated companies..................................... 287,225 97,704
Accrued taxes............................................................. 167,899 129,830
Accrued interest.......................................................... 59,489 57,101
Other..................................................................... 37,990 60,664
---------- ----------
984,442 983,724
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 656,104 637,339
Accumulated deferred investment tax credits............................... 73,141 76,187
Nuclear plant decommissioning costs....................................... 228,533 220,798
Pensions and other postretirement benefits................................ 236,516 231,365
Other..................................................................... 201,013 220,463
---------- ----------
1,395,307 1,386,152
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... __________ __________
$5,902,720 $5,856,106
========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of
these balance sheets.
43
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ------------------------
2002 2001 2002 2001
-------- -------- ---------- ----------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 86,791 $128,890 $ 168,847 $ 173,029
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 17,846 51,705 74,650 161,433
Nuclear fuel and lease amortization................ 5,037 7,627 15,821 21,741
Other amortization................................. (3,937) (3,111) (12,104) (10,783)
Deferred income taxes, net......................... 6,812 (5,910) 19,912 (1,250)
Investment tax credits, net........................ (1,015) (969) (3,046) (2,908)
Receivables........................................ 3,274 (120,852) (28,383) (105,792)
Materials and supplies............................. (1,786) (657) (4,992) 14,900
Accounts payable................................... (23,141) (49,155) 3,238 (95,336)
Other.............................................. 23,518 100,047 9,930 6,278
-------- -------- ---------- ----------
Net cash provided from operating activities...... 113,399 107,615 243,873 161,312
-------- -------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 77,505 -- 77,505 --
Short-term borrowings, net........................... 162,858 97,280 189,521 225,866
Equity contributions from parent..................... 50,000 -- 50,000 --
Redemptions and Repayments-
Preferred stock...................................... 47,017 1,000 147,017 11,716
Long-term debt....................................... 309,189 17,735 309,379 47,639
Dividend Payments-
Common stock......................................... -- 70,100 -- 175,900
Preferred stock...................................... 2,283 6,793 10,668 20,870
-------- -------- ---------- ----------
Net cash used for (provided from) financing
activities 68,126 (1,652) 150,038 30,259
-------- -------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... 40,545 93,062 102,467 108,642
Loans to associated companies.......................... -- -- -- 11,117
Loan payments from associated companies................ -- -- (205) (188)
Capital trust investments.............................. (10,325) -- (37,719) (16,279)
Sale of assets to associated companies................. -- -- -- (11,117)
Other.................................................. 7,137 8,700 21,382 33,990
-------- -------- ---------- ----------
Net cash used for investing activities........... 37,357 101,762 85,925 126,165
-------- -------- ---------- ----------
Net increase in cash and cash equivalents................. 7,916 7,505 7,910 4,888
Cash and cash equivalents at beginning of period ......... 290 238 296 2,855
-------- -------- ---------- ----------
Cash and cash equivalents at end of period................ $ 8,206 $ 7,743 $ 8,206 $ 7,743
======== ======== ========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of
these statements.
44
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of The Cleveland
Electric Illuminating Company:
We have reviewed the accompanying consolidated balance sheet of The Cleveland
Electric Illuminating Company and its subsidiaries as of September 30, 2002, and
the related consolidated statements of income and cash flows for each of the
three-month and nine-month periods ended September 30, 2002. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
45
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
CEI is a wholly owned, electric utility subsidiary of FirstEnergy.
CEI provides regulated electric distribution services in portions of northern
Ohio. CEI also provides generation services to those customers electing to
retain CEI as their power supplier. CEI continues to provide power directly to
wholesale customers under previously negotiated contracts, as well as to
alternative energy suppliers under its regulatory plan. CEI's regulatory plan
itemizes, or unbundles, the price of electricity into its component elements -
including generation, transmission, distribution and transition charges. Power
supply requirements of CEI are provided by FES - an affiliated company.
Results of Operations
- ---------------------
Operating revenues decreased $64.5 million or 10.7% in the third
quarter and $191.8 million or 11.8% in the first nine months of 2002, as
compared to the same periods of 2001. Reduced operating revenues reflect the
combined effects of a weak but recovering economy, shopping by Ohio customers
for alternative energy providers, reduced sales to wholesale customers and
weather. Kilowatt-hour sales to generation customers decreased by 13.2% in the
third quarter and 25.3% in the first nine months of 2002, compared to the same
periods last year, principally from customer choice in Ohio. Sales of electric
generation by alternative suppliers as a percent of total sales in the CEI
franchise area increased to 32.5% in the third quarter of 2002 from 17.4% in the
same period last year. During the first nine months of 2002, CEI's share of
electric generation sales in its franchise area decreased by 19.1 percentage
points, compared to the same period of 2001.
Despite higher distribution deliveries in the third quarter of 2002,
compared to the same quarter of 2001, distribution revenues decreased $1.1
million - reflecting decreases in commercial and industrial revenues partially
offset by an increase in kilowatt-hour sales to residential customers due to
unusually hot summer weather. Distribution deliveries declined by 5.0% and
revenues from electricity throughput decreased by $28.9 million in the first
nine months of 2002, compared to the same period last year, primarily due to the
weaker economic conditions earlier in the year.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, further reduced operating revenues in
the third quarter and first nine months of 2002, compared to the corresponding
periods of 2001 - reducing comparable revenues by $13.7 million and $37.8
million, respectively. These revenue reductions are deferred for future recovery
under CEI's transition plan and do not materially affect current period
earnings.
Sales revenues to wholesale customers decreased by $20.6 million in
the third quarter and $19.8 million in the year-to-date period of 2002, compared
to the same periods last year, on lower kilowatt-hour sales in both periods.
Reduced kilowatt-hour sales resulted principally from lower sales to FES
reflecting the extended outage at Davis-Besse.
The sources of changes in operating revenues during the third quarter
and first nine months of 2002, compared with the corresponding periods of 2001,
are summarized in the following table:
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Retail:
Generation sales.................... $(24.5) $ (95.5)
Distribution deliveries............. (1.1) (28.9)
Increased shopping incentives....... (13.7) (37.8)
------ -------
Total Retail........................ (39.3) (162.2)
Wholesale............................. (20.6) (19.8)
Other................................. (4.6) (9.8)
------ -------
Net Decrease in Operating Revenue..... $(64.5) $(191.8)
====== =======
Operating Expenses and Taxes
Total operating expenses and taxes declined $19.7 million in the
third quarter and $183.0 million in the first nine months of 2002 from the
corresponding periods of 2001. Purchased power costs increased $5.2 million in
the third quarter compared to the same period last year, due to higher unit
costs partially offset by reduced volume requirements supporting
46
lower generation kilowatt-hour sales. In the first nine months of 2002,
purchased power costs decreased $145.0 million compared to the same period last
year, due to lower unit costs and reduced volume requirements supporting lower
generation kilowatt-hour sales. Nuclear operating costs increased $29.7 million
in the third quarter and $61.2 million in the first nine months of 2002 from the
same periods in 2001. Costs related to the extended outage at the Davis-Besse
nuclear plant (see Davis-Besse Restoration) resulted in higher nuclear costs in
the third quarter of 2002 compared to the third quarter of 2001. In the first
nine months of 2002, nuclear costs also included amounts incurred in the first
quarter of 2002 for refueling outages at two nuclear plants (Beaver Valley Unit
2 and Davis-Besse), compared to only one refueling outage (Perry) in the first
quarter of 2001. Other operating costs increased $7.9 million in the third
quarter, compared to the same period last year, primarily due to employee
severance costs and higher distribution expenses. During the first nine months
of 2002, other operating costs decreased by $7.6 million as a result of lower
outage-related fossil production costs and uncollectible account expenses, which
were partially offset by employee severance costs and higher distribution
expenses.
Charges for depreciation and amortization decreased by $33.9 million
in the third quarter and $86.8 million in the first nine months of 2002,
compared to the same periods last year. These decreases reflect higher shopping
incentive deferrals and tax-related deferrals under CEI's transition plan in
2002, the elimination of depreciation associated with the planned sale of the
Ashtabula, Eastlake and Lakeshore generating plants (see Note 3), and the
cessation of goodwill amortization beginning January 1, 2002, upon
implementation of SFAS 142, "Goodwill and Other Intangible Assets." CEI's
goodwill amortization in the third quarter and first nine months of 2001 totaled
$9.6 million and $28.7 million, respectively.
General taxes increased by $3.5 million in the third quarter and $6.8
million in the first nine months of 2002 from the same periods in 2001. Higher
property taxes contributed to the increase in general taxes for both periods.
Kilowatt-hour sales-related taxes on higher distribution deliveries also
contributed to the increase in third quarter 2002. The increase in general taxes
for the first nine months of 2002 was partially offset by reductions due to
state tax changes in connection with the Ohio electric industry restructuring.
Other Income
A reduction in costs associated with the factoring of accounts
receivable resulted in an increase in other income in the third quarter and
first nine months of 2002, compared to the prior year - increasing other income
by $1.6 million and $4.6 million, respectively.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $3.2 million in the
third quarter and $5.0 million in the first nine months of 2002, compared to the
same periods last year, principally due to the completion of $146.0 million in
optional preferred stock redemptions. Premiums related to the optional
redemptions partially offset the lower dividend requirements. In the third
quarter 2002, CEI received an equity contribution of $50 million that
facilitated CEI's 2002 optional preferred stock redemptions.
Capital Resources and Liquidity
- -------------------------------
CEI has continuing cash requirements for planned capital expenditures
and maturing debt. During the last quarter of 2002, capital requirements for
property additions are expected to be about $48 million, including $7 million
for nuclear fuel. These capital requirements include the estimated incremental
repair costs of the unplanned outage at the Davis-Besse nuclear plant discussed
below. CEI also has sinking fund requirements for preferred stock of $17.8
million during the remainder of 2002. These cash requirements are expected to be
satisfied from internal cash and short-term credit arrangements.
As of September 30, 2002, CEI had about $8.8 million of cash and
temporary investments and $287.2 million of short-term indebtedness to
associated companies. Under its first mortgage indenture, excluding property
additions associated with the planned sale of coal-fired generating plants, CEI
had the capability to issue up to $417 million of additional first mortgage
bonds on the basis of property additions and retired bonds as of September 30,
2002. CEI has no restrictions on the issuance of preferred stock. Off-balance
sheet debt equivalents for sale and leaseback transactions of generating units
entered into in 1987 and accounts receivable factoring totaled $316 million as
of September 30, 2002.
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 FirstEnergy 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.
47
Restart activities include both hardware and management issues. Of
some 24,000 work activities identified for restarting Davis-Besse (refueling
outages typically require 6,000 work activities) approximately 60% have been
completed. 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.
FirstEnergy expects to complete refurbishment and installation of the
replacement reactor head as well as any other work related to restart of the
plant early in 2003. The NRC must authorize restart of the plant following its
formal inspection process before the unit can be returned to service.
The estimated costs (capital and expense) associated with the
extended Davis-Besse outage (CEI's share - 51.38%) in 2002 and 2003 are:
Costs of Davis-Besse Extended Outage
------------------------------------
Expenditure Range
-----------------
(In millions)
2002
----
Replace reactor vessel head (principally capital
expenditures).. ........................................... $55 - $75
Primarily operating expenses (pre-tax):
Additional maintenance (including acceleration of programs)... $115 - $135
Replacement power through September 2002...................... $85
Replacement power for October through December 2002........... $30 - $45
2003
----
Additional work to enhance reliability and performance........ $50
The replacement power costs for 2003 are estimated to be $10-$15
million per month.
Sales of Power Plants
In November 2001, FirstEnergy announced an agreement to sell three of
CEI's coal-fired power plants (see Note 3) 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 is reserving 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. FirstEnergy is
pursuing opportunities with other parties who have expressed interest in
purchasing the plants. It expects to conclude a bid process with interested
parties in the fourth quarter of 2002, with the objective of executing an
acceptable sales agreement by year-end. If FirstEnergy has not executed a sales
agreement by year-end, CEI would need to reflect up to $37 million of previously
unrecognized depreciation and other transaction costs related to these plants
from November 2001 through September 2002 on its Consolidated Statement of
Income.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of CEI's full-time employees are eligible to participate
in these plans. In accordance with the provisions of the Employment Retirement
Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of
its pension plans annually to determine if additional funding is necessary.
FirstEnergy has pre-funded a portion of the future liabilities related to its
OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy
reserves the right to change, modify or terminate the plans. Its pension plan
funding policy is to contribute annually an amount that is in accordance with
the provisions of ERISA - no contributions have been required since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate capital
resources through cash generated from operations and through existing lines of
credit to support necessary funding requirements based on anticipated plan
performance. While OPEB plan assets have also been affected by
the sharp declines in the equity market, contributions are voluntary and
declines have a limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, CEI would
be required to record an after-tax charge to equity (other comprehensive income)
of approximately $8 million in the fourth quarter of 2002 to recognize its
additional minimum pension liability of $21 million. The amount recorded will
depend upon the financial markets and interest rates in the remainder of 2002.
In addition, pension and other postretirement costs could increase by as much as
$7 million are anticipated for 2003 based on the reduction of plan assets
through October 31, 2002, due to lower rate of return assumptions and the
amortization of unrecognized losses,
48
as well as higher health care trend rates for OPEB (see Significant Accounting
Policies - Pension and Other Postretirement Benefits Accounting).
Environmental Matters
- ---------------------
CEI has been named a "potentially responsible party" (PRP) 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 September 30, 2002, based on estimates of the
total costs of cleanup, CEI's proportionate responsibility for such costs and
the financial ability of other nonaffiliated entities to pay. CEI has accrued
liabilities of approximately $2.8 million as of September 30, 2002, and does not
believe environmental remediation costs will have a material adverse effect on
its financial condition, cash flows or results of operations.
Significant Accounting Policies
- -------------------------------
CEI prepares its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect CEI's financial results. All of CEI's assets are subject
to their own specific risks and uncertainties and are regularly reviewed for
impairment. CEI's goodwill will be reviewed for impairment at least annually in
accordance with SFAS 142. CEI's annual review was completed in the third quarter
of 2002 - the results of that review indicated no impairment of goodwill. Other
assets related to the application of the policies discussed below are similarly
reviewed with their risks and uncertainties reflecting these specific factors.
CEI's more significant accounting policies are described below.
Regulatory Accounting
CEI is subject to regulation that sets the prices (rates) it is
permitted to charge customers based on the costs that regulatory agencies
determine CEI is permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated company. This rate-making process results in the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in Ohio, a significant amount of regulatory assets
have been recorded - $922 million as of September 30, 2002. CEI regularly
reviews these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
Revenue Recognition
CEI follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," CEI periodically evaluates its 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 impairment must be
recognized in the financial statements. If impairment other than of a temporary
nature has occurred, CEI recognizes a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).
49
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
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.
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced below the current assumed rate, liabilities and
pension and OPEB costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and
13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, CEI's reported pension costs would
increase. While OPEB plan assets have also been affected by sharp declines in
the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased and could affect
future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholder's equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods to
the extent the fair value of trust assets would exceed the accumulated benefit
obligation. The amount of pension liability to be recorded as of December 31,
2002, will depend upon the discount rate and asset returns experienced in 2002
(and any resulting change in FirstEnergy's assumptions).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time they are incurred rather
than when management commits to a plan of exit or disposal. It also requires the
use of fair value for the measurement of such liabilities. The new standard
supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This
new standard will be 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.
50
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $269,857 $306,512 $764,331 $841,150
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 9,524 13,671 30,342 38,439
Purchased power........................................ 85,329 137,679 247,085 312,744
Nuclear operating costs................................ 62,574 36,254 183,214 121,013
Other operating costs.................................. 43,627 38,259 114,426 114,172
-------- -------- -------- --------
Total operation and maintenance expenses........... 201,054 225,863 575,067 586,368
Provision for depreciation and amortization............ 23,413 30,818 64,529 92,833
General taxes.......................................... 14,061 13,256 41,258 43,196
Income taxes........................................... 6,287 8,951 14,618 29,440
-------- -------- -------- --------
Total operating expenses and taxes................. 244,815 278,888 695,472 751,837
-------- -------- -------- --------
OPERATING INCOME.......................................... 25,042 27,624 68,859 89,313
OTHER INCOME.............................................. 4,033 3,896 12,119 9,862
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 29,075 31,520 80,978 99,175
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt............................. 14,611 16,494 46,084 50,354
Allowance for borrowed funds used during construction.. (611) (285) (1,421) (3,548)
Other interest expense (credit)........................ 463 (1,117) (632) (3,228)
-------- -------- -------- --------
Net interest charges............................... 14,463 15,092 44,031 43,578
-------- -------- -------- --------
NET INCOME................................................ 14,612 16,428 36,947 55,597
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,211 4,030 9,145 12,105
-------- -------- -------- --------
EARNINGS ON COMMON STOCK.................................. $ 12,401 $ 12,398 $ 27,802 $ 43,492
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
51
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- -------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,593,929 $1,578,943
Less-Accumulated provision for depreciation............................... 686,171 645,865
---------- ----------
907,758 933,078
---------- ----------
Construction work in progress-
Electric plant.......................................................... 79,868 40,220
Nuclear fuel............................................................ 27,751 19,854
---------- ----------
107,619 60,074
---------- ----------
1,015,377 993,152
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 242,098 262,131
Nuclear plant decommissioning trusts...................................... 168,666 156,084
Long-term notes receivable from associated companies...................... 162,207 162,347
Other..................................................................... 3,395 4,248
---------- ----------
576,366 584,810
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 519 302
Receivables-
Customers............................................................... 6,890 5,922
Associated companies.................................................... 46,463 64,667
Other................................................................... 3,326 9,709
Notes receivable from associated companies................................ 26,752 7,607
Materials and supplies, at average cost-
Owned................................................................... 13,657 13,996
Under consignment....................................................... 21,359 17,050
Prepayments and other..................................................... 1,909 14,580
---------- ----------
120,875 133,833
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 397,629 388,846
Goodwill.................................................................. 445,732 445,732
Other..................................................................... 34,209 25,745
---------- ----------
877,570 860,323
---------- ----------
$2,590,188 $2,572,118
========== ==========
52
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- -------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding......................................... $ 195,670 $ 195,670
Other paid-in capital................................................... 428,559 328,559
Retained earnings....................................................... 135,638 113,436
---------- ----------
Total common stockholder's equity................................... 759,867 637,665
Preferred stock not subject to mandatory redemption....................... 126,000 126,000
Long-term debt............................................................ 591,600 646,174
---------- ----------
1,477,467 1,409,839
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 135,830 347,593
Accounts payable-
Associated companies.................................................... 95,076 53,960
Other................................................................... 6,847 27,418
Notes payable to associated companies..................................... 147,442 17,208
Accrued taxes............................................................. 52,542 39,848
Accrued interest.......................................................... 15,872 19,918
Other..................................................................... 34,309 40,222
---------- ----------
487,918 546,167
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 216,129 213,145
Accumulated deferred investment tax credits............................... 29,955 31,342
Nuclear plant decommissioning costs....................................... 175,008 162,426
Pensions and other postretirement benefits................................ 122,271 120,561
Other..................................................................... 81,440 88,638
---------- ----------
624,803 616,112
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$2,590,188 $2,572,118
========== ==========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance
sheets.
53
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ----------------------
2002 2001 2002 2001
--------- -------- -------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 14,612 $ 16,428 $ 36,947 $ 55,597
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 23,413 30,818 64,529 92,833
Nuclear fuel and lease amortization................ 2,765 5,495 9,009 15,905
Deferred income taxes, net......................... (5,911) (4,966) (19) (1,814)
Investment tax credits, net........................ (414) (490) (1,387) (1,463)
Receivables........................................ 22,359 3,406 23,619 7,406
Materials and supplies............................. (2,150) (689) (3,970) 10,023
Accounts payable................................... 26,894 29,074 20,545 24,583
Accrued sale leaseback costs....................... 8,905 24,879 (19,549) (4,278)
Other.............................................. 7,556 3,512 9,597 (15,885)
--------- -------- -------- ---------
Net cash provided from operating activities...... 98,029 107,467 139,321 182,907
--------- -------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net........................... 13,279 -- 130,234 --
Equity contributions from parent..................... 100,000 -- 100,000 --
Redemptions and Repayments-
Preferred stock...................................... -- -- 85,299 --
Long-term debt....................................... 167,705 1,961 179,968 33,773
Short-term borrowings, net........................... -- 7,491 -- 41,936
Dividend Payments-
Common stock......................................... -- -- 5,600 14,700
Preferred stock...................................... 2,211 4,030 7,846 12,103
--------- -------- -------- ---------
Net cash used for financing activities........... 56,637 13,482 48,479 102,512
--------- -------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... 26,636 54,670 66,897 75,179
Loans to associated companies.......................... 10,798 30,017 19,005 128,351
Capital trust investments.............................. (3,207) 57 (20,033) (17,648)
Sale of assets to associated companies................. -- -- -- (123,438)
Other.................................................. 7,099 6,933 24,756 16,679
--------- -------- -------- ---------
Net cash used for investing activities........... 41,326 91,677 90,625 79,123
--------- -------- -------- ---------
Net increase in cash and cash equivalents................. 66 2,308 217 1,272
Cash and cash equivalents at beginning of period.......... 453 349 302 1,385
--------- -------- -------- ---------
Cash and cash equivalents at end of period................ $ 519 $ 2,657 $ 519 $ 2,657
========= ======== ======== =========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
54
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of The Toledo
Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo
Edison Company and its subsidiary as of September 30, 2002, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 30, 2002. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
55
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE
provides regulated electric distribution services in portions of northern Ohio.
TE also provides generation services to those customers electing to retain TE as
their power supplier. TE continues to provide power directly to wholesale
customers under previously negotiated contracts, as well as to alternative
energy suppliers under its regulatory plan. TE's regulatory plan itemizes, or
unbundles, the price of electricity into its component elements - including
generation, transmission, distribution and transition charges. Power supply
requirements of TE are provided by FES - an affiliated company.
Results of Operations
- ---------------------
Operating revenues decreased $36.7 million or 12.0% in the third
quarter and $76.8 million or 9.1% in the first nine months of 2002, as compared
to the same periods of 2001. Reduced operating revenues reflect the combined
effects of a weak but recovering economy, shopping by Ohio customers for
alternative energy providers, reduced sales to wholesale customers and weather.
Kilowatt-hour sales to generation customers decreased by 11.3% in the third
quarter and 11.6% in the first nine months of 2002, compared to the same periods
last year, due principally to customer choice in Ohio. Sales of electric
generation by alternative suppliers as a percent of total sales delivered in the
TE franchise area increased to 19.4% in the third quarter of 2002 from 7.6% in
the same period last year. During the first nine months of 2002, TE's share of
electric generation sales in its franchise areas decreased by 11.6 percentage
points, compared to the same period in 2001.
Despite higher distribution deliveries in the third quarter and first
nine months of 2002, compared to the same periods of 2001, distribution revenues
decreased $5.0 million and $12.3 million, respectively, reflecting decreases in
commercial and industrial revenues partially offset by an increase in
kilowatt-hour sales to residential customers due to unusually hot summer
weather.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, further magnified the effect of
generation sales reductions to operating revenues in the third quarter and first
nine months of 2002, compared to the corresponding periods of 2001 - reducing
comparable revenues by $4.8 million and $12.5 million, respectively. These
revenue reductions are deferred for future recovery under TE's transition plan
and do not materially affect current period earnings.
Sales revenues to wholesale customers decreased by $17.5 million in
the third quarter and $27.0 million in the year-to-date period of 2002, compared
to the same periods last year, on lower kilowatt-hour sales in both periods.
Reduced kilowatt-hour sales resulted principally from lower sales to FES
reflecting the extended outage at Davis-Besse.
The sources of changes in operating revenues during the third quarter
and first nine months of 2002, compared with the corresponding periods of 2001,
are summarized in the following table:
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Retail:
Generation sales....................... $ (8.5) $(23.5)
Distribution deliveries................ (5.0) (12.3)
Increased shopping incentives.......... (4.8) (12.5)
------ ------
Total Retail........................... (18.3) (48.3)
Wholesale................................ (17.5) (27.0)
Other.................................... ( 0.9) (1.5)
------ ------
Net Decrease in Operating Revenue........ $(36.7) $(76.8)
====== ======
56
Operating Expenses and Taxes
Total operating expenses and taxes declined by $34.1 million in the
third quarter and $56.4 million in the first nine months of 2002 from the
corresponding periods of 2001. Purchased power costs decreased $52.4 million and
$65.7 million in the third quarter and first nine months of 2002, compared to
the same periods last year, due to lower unit costs and reduced volume
requirements supporting lower generation kilowatt-hour sales.
Nuclear operating costs increased by $26.3 million in the third
quarter and $62.2 million in the first nine months of 2002 from the same periods
in 2001. Costs related to the extended outage at the Davis-Besse nuclear plant
(see Davis-Besse Restoration) resulted in higher nuclear costs in the third
quarter of 2002 compared to the third quarter of last year. During the first
nine months of 2002, costs also included amounts incurred in the first quarter
of 2002 for refueling outages at two nuclear plants (Beaver Valley Unit 2 and
Davis-Besse), compared to only one refueling outage (Perry) in the first quarter
of 2001. Other operating costs increased $5.4 million in the third quarter of
2002, compared to the same period last year, in large part due to employee
severance costs and higher distribution and uncollectible accounts expenses.
Charges for depreciation and amortization decreased by $7.4 million
in the third quarter and $28.3 million in the first nine months of 2002,
compared to the same periods last year. These decreases reflect higher shopping
incentive deferrals and tax-related deferrals under TE's transition plan in
2002, the elimination of depreciation associated with the planned sale of the
Bay Shore generating plant (see Note 3) and the cessation of goodwill
amortization beginning January 1, 2002, upon implementation of SFAS 142,
"Goodwill and Other Intangible Assets." TE's goodwill amortization in the third
quarter and first nine months of 2001 totaled $3.1 million and $9.3 million,
respectively.
General taxes decreased by $1.9 million in the first nine months of
2002, compared to the same period last year, due to state tax changes in
connection with the Ohio electric industry restructuring.
Capital Resources and Liquidity
- -------------------------------
TE has continuing cash requirements for planned capital expenditures
and maturing debt. During the last quarter of 2002, capital requirements for
property additions are expected to be about $33 million, including $3 million
for nuclear fuel. These capital requirements include the estimated incremental
repair costs of the unplanned outage at the Davis-Besse nuclear plant discussed
below. TE also has sinking fund requirements for maturing long-term debt of $0.4
million during the remainder of 2002. These cash requirements are expected to be
satisfied from internal cash and short-term credit arrangements.
As of September 30, 2002, TE had about $27.3 million of cash and
temporary investments and $147.4 million of short-term indebtedness to
associated companies. Under its first mortgage indenture, excluding property
additions associated with the planned sale of the Bay Shore Plant, TE could not
issue any additional first mortgage bonds as of September 30, 2002. Under the
earnings coverage test contained in TE's charter, no preferred stock could be
issued based on earnings through the third quarter of 2002. Off-balance sheet
debt equivalents for sale and leaseback transactions of generating units entered
into in 1987 totaled $654 million as of September 30, 2002. In the third quarter
2002, TE received an equity contribution of $100 million from FirstEnergy that
facilitated TE's optional long-term debt and preferred stock redemptions.
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 FirstEnergy 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. Of
some 24,000 work activities identified for restarting Davis-Besse (refueling
outages typically require 6,000 work activities) approximately 60% have been
completed. 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.
FirstEnergy expects to complete refurbishment and installation of the
replacement reactor head as well as any other work related to restart of the
plant early in 2003. The NRC must authorize restart of the plant following its
formal inspection process before the unit can be returned to service.
The estimated costs (capital and expense) associated with the
extended Davis-Besse outage (TE share - 48.62%) in 2002 and 2003 are:
57
Costs of Davis-Besse Extended Outage
- ------------------------------------
Expenditure Range
-----------------
(In millions)
2002
- ----
Replace reactor vessel head (principally capital expenditures).. $55 - $75
Primarily operating expenses (pre-tax):
Additional maintenance (including acceleration of programs)..... $115 - $135
Replacement power through September 2002........................ $85
Replacement power for October through December 2002............. $30 - $45
2003
- ----
Additional work to enhance reliability and performance.......... $50
The replacement power costs for 2003 are estimated to be $10-$15
million per month.
Sale of Bay Shore Power Plant
In November 2001, FirstEnergy announced an agreement to sell TE's 648
megawatt Bay Shore Plant (see Note 3) 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 is reserving 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. FirstEnergy is
pursuing opportunities with other parties who have expressed interest in
purchasing the plants. It expects to conclude a bid process with interested
parties in the fourth quarter of 2002, with the objective of executing an
acceptable sales agreement by year-end. If FirstEnergy has not executed a sales
agreement by year-end, TE would need to reflect up to $10 million of previously
unrecognized depreciation and other transaction costs related to these plants
from November 2001 through September 2002 on its Consolidated Statement of
Income.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of TE's full-time employees are eligible to participate
in these plans. In accordance with the provisions of the Employment Retirement
Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of
its pension plans annually to determine if additional funding is necessary.
FirstEnergy has pre-funded a portion of the future liabilities related to its
OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy
reserves the right to change, modify or terminate the plans. Its pension plan
funding policy is to contribute annually an amount that is in accordance with
the provisions of ERISA - no contributions have been required since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts in 2004 or future years. FirstEnergy believes that it has adequate
capital resources through cash generated from operations and through existing
lines of credit to support necessary funding requirements based on anticipated
plan performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, TE would be
required to record an after-tax charge to equity (other comprehensive income) of
approximately $4 million in the fourth quarter of 2002 to recognize its
additional minimum pension liability of $11 million. The amount recorded will
depend upon the financial markets and interest rates in the remainder of
2002. In addition, pension and other postretirement costs could increase by as
much as $4 million in 2003 based on the reduction of plan assets through October
31, 2002, due to adverse equity market conditions, lower rate of return
assumptions and the amortization of unrecognized losses, as well as higher
health care trend rates for OPEB (see Significant Accounting Policies - Pension
and Other Postretirement Benefits Accounting).
Environmental Matters
- ---------------------
TE has been named a "potentially responsible party" (PRP) 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 September 30, 2002, based on estimates of the
total costs of cleanup, TE's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. TE has accrued
liabilities of approximately $0.2 million as of September 30, 2002, and does not
58
believe environmental remediation costs will have a material adverse effect on
its financial condition, cash flows or results of operations.
Significant Accounting Policies
- -------------------------------
TE prepares its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect TE's financial results. All of TE's assets are subject
to their own specific risks and uncertainties and are regularly reviewed for
impairment. TE's goodwill will be reviewed for impairment at least annually in
accordance with SFAS 142. FirstEnergy's annual review was completed in the third
quarter of 2002 - the results of that review indicate no impairment of goodwill.
Other assets related to the application of the policies discussed below are
similarly reviewed with their risks and uncertainties reflecting these specific
factors. TE's more significant accounting policies are described below.
Regulatory Accounting
TE is subject to regulation that sets the prices (rates) it is
permitted to charge customers based on the costs that regulatory agencies
determine TE is permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated company. This rate-making process results in the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in Ohio, a significant amount of regulatory assets
have been recorded - $398 million as of September 30, 2002. TE regularly reviews
these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
Revenue Recognition
TE follows the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," TE periodically evaluates its 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 impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, TE recognizes a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
59
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.
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced below the current assumed rate, liabilities and
pension and OPEB costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and
13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, TE's reported pension costs would
increase. While OPEB plan assets have also been affected by sharp declines in
the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased and could affect
future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholder's equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods to
the extent the fair value of trust assets would exceed the accumulated benefit
obligation. The amount of pension liability to be recorded as of December 31,
2002, will depend upon the discount rate and asset returns experienced in 2002
(and any resulting change in FirstEnergy assumptions).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time they are incurred rather
than when management commits to a plan of exit or disposal. It also requires the
use of fair value for the measurement of such liabilities. The new standard
supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This
new standard will be 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.
60
PENNSYLVANIA POWER COMPANY
STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $131,917 $121,349 $383,989 $374,447
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 6,568 5,065 19,280 17,593
Purchased power........................................ 40,057 34,389 115,683 113,948
Nuclear operating costs................................ 19,155 47,316 60,960 86,833
Other operating costs.................................. 13,365 11,909 33,034 34,102
-------- -------- -------- --------
Total operation and maintenance expenses........... 79,145 98,679 228,957 252,476
Provision for depreciation and amortization............ 14,203 14,307 42,615 42,837
General taxes.......................................... 6,720 4,542 18,730 10,283
Income taxes........................................... 13,044 1,218 38,295 27,375
-------- -------- -------- --------
Total operating expenses and taxes................. 113,112 118,746 328,597 332,971
-------- -------- -------- --------
OPERATING INCOME.......................................... 18,805 2,603 55,392 41,476
OTHER INCOME.............................................. 739 959 1,880 2,581
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 19,544 3,562 57,272 44,057
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest expense....................................... 4,188 4,527 12,554 13,929
Allowance for borrowed funds used during construction.. (447) (237) (1,044) (577)
-------- -------- -------- --------
Net interest charges............................... 3,741 4,290 11,510 13,352
-------- -------- -------- --------
NET INCOME (LOSS)......................................... 15,803 (728) 45,762 30,705
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 926 926 2,778 2,778
-------- -------- -------- --------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK................ $ 14,877 $ (1,654) $ 42,984 $ 27,927
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these statements.
61
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $674,694 $664,432
Less-Accumulated provision for depreciation............................... 308,799 290,216
-------- --------
365,895 374,216
-------- --------
Construction work in progress-
Electric plant.......................................................... 37,541 24,141
Nuclear fuel............................................................ 815 2,921
-------- --------
38,356 27,062
-------- --------
404,251 401,278
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 118,339 116,634
Long-term notes receivable from associated companies...................... 39,015 39,290
Other..................................................................... 21,556 21,597
-------- --------
178,910 177,521
-------- --------
CURRENT ASSETS:
Cash and cash equivalents................................................. 1,454 67
Receivables-
Customers (less accumulated provisions of $707,000 and $619,000,
respectively, for uncollectible accounts)............................. 45,833 40,890
Associated companies.................................................... 35,330 36,491
Other................................................................... 4,649 4,787
Notes receivable from associated companies................................ 22,830 54,411
Materials and supplies, at average cost................................... 29,647 25,598
Prepayments............................................................... 9,579 5,682
-------- --------
149,322 167,926
-------- --------
DEFERRED CHARGES:
Regulatory assets......................................................... 170,362 208,838
Other..................................................................... 4,377 4,534
-------- --------
174,739 213,372
-------- --------
$907,222 $960,097
======== ========
62
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, $30 par value, authorized 6,500,000 shares -
6,290,000 shares outstanding.......................................... $188,700 $188,700
Other paid-in capital................................................... (310) (310)
Retained earnings....................................................... 49,882 35,398
-------- --------
Total common stockholder's equity................................... 238,272 223,788
Preferred stock-
Not subject to mandatory redemption..................................... 39,105 39,105
Subject to mandatory redemption......................................... 14,250 14,250
Long-term debt-
Associated companies.................................................... -- 21,064
Other................................................................... 185,978 240,983
-------- --------
477,605 539,190
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt-
Associated companies.................................................... -- 18,090
Other................................................................... 66,572 12,075
Accounts payable-
Associated companies.................................................... 32,139 50,604
Other................................................................... 1,161 1,441
Accrued taxes............................................................. 23,879 18,853
Accrued interest.......................................................... 3,484 5,264
Other..................................................................... 9,860 9,675
-------- --------
137,095 116,002
-------- --------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 122,072 136,808
Accumulated deferred investment tax credits............................... 3,884 4,108
Nuclear plant decommissioning costs....................................... 118,801 117,096
Other..................................................................... 47,765 46,893
-------- --------
292,522 304,905
-------- --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
-------- --------
$907,222 $960,097
======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these balance sheets.
63
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ---------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 15,803 $ (728) $ 45,762 $ 30,705
Adjustments to reconcile net income (loss) to net
cash from operating activities-
Provision for depreciation and amortization.......... 14,203 14,307 42,615 42,837
Nuclear fuel and lease amortization.................. 5,054 3,733 14,622 12,974
Deferred income taxes, net........................... (1,731) (2,501) (5,606) (8,537)
Investment tax credits, net.......................... (643) (688) (1,963) (2,098)
Receivables.......................................... 376 16,469 (3,644) 17,783
Materials and supplies............................... (1,766) (159) (4,049) 6,149
Accounts payable..................................... 161 8,257 (18,745) (17,750)
Accrued taxes........................................ (18,063) 6,758 5,026 10,127
Other................................................ 4,498 (2,738) (3,664) (11,354)
-------- -------- -------- --------
Net cash provided from operating activities...... 17,892 42,710 70,354 80,836
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 14,500 239 14,500 32,842
Redemptions and Repayments-
Long-term debt....................................... 15,031 37,970 56,321 47,692
Dividend Payments-
Common stock......................................... 20,700 21,100 28,500 27,400
Preferred stock...................................... 926 926 2,778 2,778
-------- -------- -------- --------
Net cash used for financing activities........... 22,157 59,757 73,099 45,028
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... 8,210 7,910 24,636 21,820
Loans to associated companies.......................... -- 10,245 -- 41,073
Loan payment from parent............................... (14,982) (3,870) (31,688) (17,510)
Sale of assets to associated companies................. -- -- -- (6,053)
Other.................................................. 1,643 319 2,920 (2,541)
-------- -------- -------- --------
Net cash used for (provided from) investing
activities ...................................... (5,129) 14,604 (4,132) 36,789
-------- -------- -------- --------
Net increase (decrease) in cash and cash equivalents...... 864 (31,651) 1,387 (981)
Cash and cash equivalents at beginning of period.......... 590 34,145 67 3,475
-------- -------- -------- --------
Cash and cash equivalents at end of period................ $ 1,454 $ 2,494 $ 1,454 $ 2,494
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these statements.
64
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of Pennsylvania
Power Company:
We have reviewed the accompanying balance sheet of Pennsylvania Power Company as
of September 30, 2002, and the related statements of income and cash flows for
each of the three-month and nine-month periods ended September 30, 2002. These
financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
65
PENNSYLVANIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Penn is a wholly owned electric utility subsidiary of OE. Penn
provides regulated electric distribution services in western Pennsylvania. Penn
also provides generation services to those customers electing to retain Penn as
their power supplier. Penn provides power directly to wholesale customers under
previously negotiated contracts. Penn's regulatory plan itemizes, or unbundles,
the price of electricity into its component elements - including generation,
transmission, distribution and transition charges. Penn's power supply
requirements are provided by FES - an affiliated company.
Results of Operations
- ---------------------
Operating revenues increased $10.6 million or 8.7% in the third
quarter and $9.5 million or 2.5% in the first nine months of 2002, as compared
to the same periods of 2001. Higher operating revenues in the third quarter of
2002 primarily resulted from warmer summer weather in 2002, compared to the same
period in 2001. Operating revenues in the first nine months of 2002 also
benefited from the return of generation customers previously served by
alternative suppliers. During the first nine months of 2002, Penn's share of
electric generation sales in its franchise area increased by 4.7 percentage
points, compared to the same period in 2001.
Distribution deliveries increased by 8.0% in the third quarter and
2.3% in the first nine months of 2002, compared to the same periods last year,
increasing revenues from electricity throughput by $3.2 million and $2.9
million, respectively. Residential sales, which benefited from unusually hot
summer weather, increased in both periods. Sales to commercial and industrial
customers contributed to the third quarter increase but partially offset the
increase in residential sales in the nine-month period due to the weaker
economic environment earlier in the year.
Sales to wholesale customers were also higher in the third quarter of
2002, compared to the same period last year. During the first nine months of
2002, lower wholesale revenues partially offset higher generation and
distribution revenues. Reduced sales revenues from FES accounted for nearly all
of the decrease in wholesale revenues in the year to date period.
The sources of changes in operating revenues during the third quarter
and first nine months of 2002, compared with the corresponding periods of 2001,
are summarized in the following table:
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Retail:
Generation sales...................... $ 3.2 $13.1
Distribution deliveries............... 3.2 2.9
----- -----
Total Retail.......................... 6.4 16.0
Wholesale............................... 3.8 (7.9)
Other................................... 0.4 1.4
----- -----
Net Increase in Operating Revenue....... $10.6 $ 9.5
===== =====
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $5.6 million in the
third quarter and $4.4 million in the first nine months of 2002 from the
corresponding periods of 2001. Purchased power costs increased $5.7 million in
the third quarter of 2002 from the same quarter last year as a result of higher
volume requirements and increased unit costs. During the first nine months,
purchased power costs increased $1.7 million from 2001, primarily attributable
to higher volume requirements more than offsetting lower unit costs. Nuclear
operating costs decreased $28.2 million in the third quarter of 2002, compared
to the corresponding period last year, primarily due to the absence of a
refueling outage in the third quarter of 2002; Beaver Valley Unit 1 (65% owned)
experienced a refueling outage in the third quarter of 2001. In the first nine
months of 2002, nuclear operating costs decreased $25.9 million from the same
period last year as a result of costs associated with two refueling outages in
2001 compared to only one refueling outage in 2002.
66
General taxes increased by $2.2 million in the third quarter and $8.4
million in the first nine months of 2002 from the same periods in 2001. An
increase in the gross receipts tax rate for 2002 contributed to the increase in
general taxes for both periods. The successful resolution of certain property
tax issues in the second quarter of 2001 provided a one-time benefit of $3.0
million in that year.
Capital Resources and Liquidity
- -------------------------------
Penn has continuing cash requirements for planned capital
expenditures and maturing debt. During the fourth quarter of 2002, capital
requirements for property additions and capital leases are expected to be about
$21 million, including $8 million for nuclear fuel. Penn also has sinking fund
requirements for preferred stock and maturing long-term debt of $1.2 million
during the remainder of 2002. These requirements are expected to be satisfied
from internal cash and/or short-term credit arrangements.
As of September 30, 2002, Penn had about $24.3 million of cash and
temporary investments and no short-term indebtedness. Under its first mortgage
indenture, as of September 30, 2002, Penn had the capability to issue up to $310
million of additional first mortgage bonds on the basis of property additions
and retired bonds. Under the earnings coverage test contained in Penn's charter,
$317 million of preferred stock (assuming no additional debt was issued) could
be issued based on earnings through the third quarter of 2002.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of Penn's full-time employees are eligible to
participate in these plans. In accordance with the provisions of the Employment
Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded
status of its pension plans annually to determine if additional funding is
necessary. FirstEnergy has pre-funded a portion of the future liabilities
related to its OPEB plans. Under the terms of its postretirement benefit plans,
FirstEnergy reserves the right to change, modify or terminate the plans. Its
pension plan funding policy is to contribute annually an amount that is in
accordance with the provisions of ERISA - no contributions have been required
since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate access
to capital resources through cash generated from operations and through existing
lines of credit to support necessary funding requirements based on anticipated
plan performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, Penn would
be required to record an after-tax charge to equity (other comprehensive income)
of approximately $12 million in the fourth quarter of 2002 to recognize its
additional minimum pension liability of $22 million. The amount recorded will
depend upon the financial markets and interest rates in the remainder of 2002.
In addition, pension and other postretirement costs could increase by as much as
$2 million in 2003 based on the reduction of plan assets through October 31,
2002, lower rate of return assumptions and the amortization of unrecognized
losses, as well as higher health care trend rates for OPEB (see Significant
Accounting Policies - Pension and Other Postretirement Benefits Accounting).
Significant Accounting Policies
- -------------------------------
Penn prepares its financial statements in accordance with accounting
principles generally accepted in the United States. Application of these
principles often requires a high degree of judgment, estimates and assumptions
that affect Penn's financial results. All of Penn's 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.
Penn's more significant accounting policies are described below.
Regulatory Accounting
Penn is subject to regulation that sets the prices (rates) it is
permitted to charge customers based on the costs that regulatory agencies
determine Penn is 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 - $170 million as of
September 30, 2002. Penn regularly reviews 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.
67
Revenue Recognition
Penn follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," Penn periodically evaluates its 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 an impairment other than of a
temporary nature has occurred, Penn would be required to recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
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.
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced below the current assumed rate, liabilities and
pension and OPEB costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and
13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, Penn's reported pension costs would
increase. While OPEB plan assets have also been affected by sharp declines in
the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased and could affect
future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common
68
stockholder's equity through an after-tax charge to other comprehensive income
(OCI), and would not affect net income for 2002. The charge to OCI would reverse
in future periods to the extent the fair value of trust assets would exceed the
accumulated benefit obligation. The amount of pension liability to be recorded
as of December 31, 2002, will depend upon the discount rate and asset returns
experienced in 2002 (and any resulting change in FirstEnergy's assumptions).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time these costs are incurred
rather than when management commits to a plan of exit or disposal. It also
requires the use of fair value for the measurement of such liabilities. The new
standard supersedes guidance provided by Emerging Issues Task Force Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." This new standard will be 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.
69
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2002 2001 2002 2001
-------- -------- ---------- ----------
(In thousands)
OPERATING REVENUES........................................ $779,955 | $672,131 $1,731,900 | $1,654,867
-------- | -------- ---------- | ----------
| |
OPERATING EXPENSES AND TAXES: | |
Fuel................................................... 1,873 | 1,584 4,347 | 4,362
Purchased power........................................ 453,081 | 354,704 913,532 | 845,997
Other operating costs.................................. 50,587 | 59,815 193,204 | 191,271
-------- | -------- ---------- | ----------
Total operation and maintenance expenses........... 505,541 | 416,103 1,111,083 | 1,041,630
Provision for depreciation and amortization............ 67,645 | 62,272 186,919 | 186,705
General taxes.......................................... 17,740 | 18,295 39,037 | 48,949
Income taxes........................................... 67,689 | 57,296 134,093 | 116,627
-------- | -------- ---------- | ----------
Total operating expenses and taxes................. 658,615 | 553,966 1,471,132 | 1,393,911
-------- | -------- ---------- | ----------
| |
OPERATING INCOME.......................................... 121,340 | 118,165 260,768 | 260,956
| |
| |
OTHER INCOME (EXPENSE).................................... 1,269 | (2,756) 6,291 | 803
-------- | -------- ---------- | ----------
| |
| |
INCOME BEFORE NET INTEREST CHARGES........................ 122,609 | 115,409 267,059 | 261,759
-------- | -------- ---------- | ----------
| |
NET INTEREST CHARGES: | |
Interest on long-term debt............................. 23,721 | 23,724 69,206 | 67,754
Allowance for borrowed funds used during construction.. (301) | 170 (880)| (261)
Deferred interest...................................... (3,722) | (4,585) (5,107)| (10,991)
Other interest expense (credit)........................ (538) | 2,279 (2,315)| 8,650
Subsidiaries' preferred stock dividend requirements.... 2,674 | 2,675 8,021 | 8,025
-------- | -------- ---------- | ----------
Net interest charges............................... 21,834 | 24,263 68,925 | 73,177
-------- | -------- ---------- | ----------
| |
| |
NET INCOME................................................ 100,775 | 91,146 198,134 | 188,582
| |
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... (2,773) | 1,299 (1,589)| 4,081
-------- | -------- ---------- | ----------
| |
EARNINGS ON COMMON STOCK.................................. $103,548 | $ 89,847 $ 199,723 | 184,501
======== | ======== ========== | ==========
The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these
statements.
70
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $3,519,541 $3,431,823
Less-Accumulated provision for depreciation............................... 1,397,661 1,313,259
---------- ----------
2,121,880 2,118,564
Construction work in progress-
Electric plant.......................................................... 36,032 60,482
---------- ----------
2,157,912 2,179,046
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 106,782 114,899
Nuclear fuel disposal trust............................................... 146,809 137,098
Long-term notes receivable from associated companies...................... 20,333 20,333
Other..................................................................... 15,012 6,643
---------- ----------
288,936 278,973
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 61,592 31,424
Receivables-
Customers (less accumulated provisions of $11,799,000 and $12,923,000,
respectively, for uncollectible accounts)............................. 236,882 226,392
Associated companies.................................................... 301 6,412
Other................................................................... 20,998 20,729
Materials and supplies, at average cost................................... 1,304 1,348
Prepayments and other..................................................... 55,137 16,569
---------- ----------
376,214 302,874
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 3,204,360 3,324,804
Goodwill.................................................................. 1,944,164 1,926,526
Other..................................................................... 20,806 27,775
---------- ----------
5,169,330 5,279,105
---------- ----------
$7,992,392 $8,039,998
========== ==========
71
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, par value $10 per share, authorized 16,000,000 shares -
15,371,270 shares outstanding......................................... $ 153,713 $ 153,713
Other paid-in capital................................................... 2,992,374 2,981,117
Accumulated other comprehensive loss.................................... (828) (472)
Retained earnings....................................................... 105,366 29,343
---------- ----------
Total common stockholder's equity................................... 3,250,625 3,163,701
Preferred stock-
Not subject to mandatory redemption..................................... 12,649 12,649
Subject to mandatory redemption......................................... -- 44,868
Company-obligated mandatorily redeemable preferred securities............. 125,246 125,250
Long-term debt............................................................ 1,216,989 1,224,001
---------- ----------
4,605,509 4,570,469
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 169,414 60,848
Accounts payable-
Associated companies.................................................... 165,611 171,168
Other................................................................... 106,990 89,739
Notes payable to associated companies..................................... -- 18,149
Accrued taxes............................................................. 15,084 35,783
Accrued interest.......................................................... 32,596 25,536
Other..................................................................... 138,630 79,589
---------- ----------
628,325 480,812
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 613,112 514,216
Accumulated deferred investment tax credits............................... 10,792 13,490
Power purchase contract loss liability.................................... 1,712,144 1,968,823
Nuclear fuel disposal costs............................................... 165,543 163,377
Nuclear plant decommissioning costs....................................... 139,356 137,424
Other..................................................................... 117,611 191,387
---------- ----------
2,758,558 2,988,717
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ---------
$7,992,392 $8,039,998
========== ==========
The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these
balance sheets.
72
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2002 2001 2002 2001
--------- --------- --------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES: | |
Net income................................................ $ 100,775 | $ 91,146 $ 198,134 | $ 188,582
Adjustments to reconcile net income to net | |
cash from operating activities- | |
Provision for depreciation and amortization........ 67,645 | 62,272 186,919 | 186,705
Other amortization................................. (828) | 2,995 623 | 21,585
Deferred costs, net................................ (122,338) | (189,228) (231,286) | (303,102)
Deferred income taxes, net......................... 48,583 | 50,305 85,123 | 70,223
Investment tax credits, net........................ (899) | (899) (2,698) | (2,698)
Receivables........................................ (14,584) | 44,869 (4,647) | (60,517)
Materials and supplies............................. (1) | 1 44 | (842)
Accounts payable................................... (21,250) | (20,049) 11,694 | (50,080)
Prepayments........................................ 41,706 | 39,247 (28,944) | 65,712
Accrued taxes...................................... 7,761 | 20,984 (20,699) | 54,285
Other.............................................. (10,132) | 2,626 (8,641) | (14,624)
--------- | --------- --------- | ---------
Net cash provided from operating activities...... 96,438 | 104,269 185,622 | 155,229
--------- | --------- --------- | ---------
| |
CASH FLOWS FROM FINANCING ACTIVITIES: | |
New Financing- | |
Long-term debt....................................... -- | -- 318,106 | 148,796
Redemptions and Repayments- | |
Preferred stock...................................... 46,500 | 8,333 51,500 | 10,833
Long-term debt....................................... 146,033 | -- 196,033 | --
Short-term borrowings, net........................... -- | 106,000 18,149 | 29,200
Dividend Payments- | |
Common stock......................................... 57,700 | -- 123,700 | 75,000
Preferred stock...................................... 256 | 1,299 2,000 | 4,081
--------- | --------- --------- | ---------
Net cash used for (provided from) financing | |
activities ..................................... 250,489 | 115,632 73,276 | (29,682)
--------- | --------- --------- | ---------
| |
CASH FLOWS FROM INVESTING ACTIVITIES: | |
Property additions..................................... 23,567 | 30,921 70,401 | 109,006
Decommissioning trust investments...................... 304 | 304 1,013 | 902
Other.................................................. 7,782 | (469) 10,764 | 2,852
--------- | --------- --------- | ---------
Net cash used for investing activities........... 31,653 | 30,756 82,178 | 112,760
--------- | --------- --------- | ---------
| |
Net increase (decrease) in cash and cash equivalents...... (185,704) | (42,119) 30,168 | 72,151
Cash and cash equivalents at beginning of period.......... 247,296 | 116,291 31,424 | 2,021
--------- | --------- --------- | ---------
Cash and cash equivalents at end of period................ $ 61,592 | $ 74,172 $ 61,592 | $ 74,172
========= | ========= ========= | =========
The preceding Notes to Financial Statements as they relate to Jersey Power & Light Company are an integral part of these
statements.
73
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of Jersey Central
Power & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central
Power & Light Company and its subsidiaries as of September 30, 2002, and the
related consolidated statements of income and cash flows for each of the
three-month and nine-month periods ended September 30, 2002. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
74
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
JCP&L is a wholly owned electric utility subsidiary of FirstEnergy.
JCP&L conducts business in northern, western and east central New Jersey,
offering regulated electric transmission and distribution services. JCP&L also
provides power to those customers electing to retain them as their power
supplier. JCP&L's regulatory plan itemizes, or unbundles, the price of
electricity into its component elements - including generation, transmission,
distribution and transition charges. JCP&L was formerly a wholly owned
subsidiary of GPU, Inc., which merged with FirstEnergy on November 7, 2001.
Results of Operations
- ---------------------
Operating revenues increased by $107.8 million or 16.0% in the third
quarter of 2002, and $77.0 million or 4.7% in the first nine months of 2002,
compared to the same periods in 2001. The sources of the changes in operating
revenues, as compared to the same periods in 2001, are summarized in the
following table.
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Change in kilowatt-hour sales due to level of retail
customers shopping for generation service......... $ 0.4 $43.5
Change in other retail kilowatt-hour sales........... 41.3 3.0
Change in wholesale sales............................ 55.3 16.4
All other changes.................................... 10.8 14.1
------ -----
Net Increase in Operating Revenues................... $107.8 $77.0
====== =====
Electric Sales
In the first nine months of 2002, a reduction in the number of
customers who received their power from alternate suppliers continued to have a
positive effect on operating revenues. During the first nine months of 2001,
5.7% of kilowatt-hours delivered were to shopping customers, whereas only 0.6%
of kilowatt-hours delivered during the same period in 2002 were to shopping
customers. In addition to this increase in revenues from returning shopping
customers, warmer weather in the third quarter of 2002 contributed to an
increase in retail distribution deliveries. JCP&L also experienced a significant
increase in sales to wholesale customers during the first nine months of 2002. A
decline in economic conditions resulted in a slight decrease in sales to
industrial customers for the nine months ended September 30, 2002; however,
economic conditions continued to improve during the third quarter of 2002,
resulting in an increase in industrial sales during that period. Changes in
kilowatt-hour deliveries by customer class during the three and nine month
periods ended September 30, 2002, as compared to the same periods in 2001, are
summarized in the following table:
Changes in Distribution Deliveries
and Wholesale Generation Sales
------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Residential........................... 16.2% 5.3%
Commercial............................ 6.9% 2.8%
Industrial............................ 4.3% (0.4)%
----- ----
Total Retail..................... 10.8% 3.4%
Wholesale............................. 174.5% 63.3%
----- ----
Total................................. 33.9% 9.5%
===== ====
75
Operating Expenses and Taxes
Total operating expenses and taxes increased $104.6 million in the
third quarter of 2002, and $77.2 million in the first nine months of 2002,
compared to the same periods in 2001. Purchased power costs increased $98.4
million and $67.5 million for the three and nine month periods ended September
30, 2002, respectively, compared to the same periods in 2001, as a result of
additional power required and higher unit costs. A decrease in other operating
costs of $9.2 million in the third quarter of 2002, compared to the same period
in 2001, was primarily attributable to the absence of employee severance and
retention costs in 2001, and lower accrued vacation expense and the deferral of
uncollectible expenses under a new tariff rider. An increase in other operating
costs of $1.9 million in the first nine months of 2002, compared to the same
period in 2001, was primarily due to increased pension and other employee
benefit costs, offset by the decreases discussed for the third quarter.
Depreciation and amortization expenses increased $5.4 million for the
quarter ended September 30, 2002, compared to the same period in 2001. The
increase was primarily attributed to amortization associated with the bondable
transition property transferred to JCP&L Transition Funding LLC in the second
quarter of 2002, as well as higher depreciation due to higher average
depreciable plant balances in the quarter ended September 30, 2002 versus the
same period in 2001. These increases were partially offset by the cessation of
amortization of regulatory assets related to the net investment in the
previously divested Oyster Creek Nuclear Generating Station.
General taxes decreased $9.9 million in the first nine months of
2002, compared to the same period in 2001, due principally to a reduction in the
transitional energy facilities assessment during the second quarter of 2002.
Other Income
Other income increased $4.0 million in the third quarter of 2002, and
$5.5 million in the first nine months of 2002, compared to the same periods in
2001, primarily due to the absence in 2002 of net losses incurred in 2001 on
futures contracts and options.
Net Interest Charges
Net interest charges decreased $2.4 million in the third quarter of
2002, and $4.3 million in the first nine months of 2002, compared to the same
periods in 2001, primarily due to reduced short-term borrowing levels and the
amortization of fair value adjustments recognized in connection with the merger.
Net interest charges were also affected by the issuance of $150 million of notes
in May 2001, and $320 million of transition bonds by a special purpose finance
subsidiary in June 2002, as well as the redemption of $40 million of notes in
November 2001, $50 million of notes in March 2002 and $142 million of notes in
July 2002. These transactions had an offsetting effect on net interest charges
for the quarter ended September 30, 2002, and resulted in a $1.5 million
increase in net interest charges for the nine months ended September 30, 2002.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $4.1 million in the
third quarter of 2002, and $5.7 million in the first nine months of 2002,
compared to the same periods in 2001, primarily due to the recognition of a $2.9
million gain on the reacquisition of $29.8 million of preferred stock in the
third quarter of 2002, and lower preferred stock dividends.
Capital Resources and Liquidity
- -------------------------------
JCP&L has continuing cash requirements for planned capital
expenditures, which are expected to be about $41.0 million during the remaining
three months of 2002. These requirements are expected to be satisfied from
internal cash and/or short-term credit arrangements.
As of September 30, 2002, JCP&L had about $61.6 million of cash and
temporary investments, and no short-term indebtedness. JCP&L may borrow from its
affiliates on a short-term basis. JCP&L will not issue first mortgage bonds
(FMBs) other than as collateral for senior notes, since its senior note
indenture prohibits (subject to certain exceptions) it from issuing any debt
which is senior to the senior notes. As of September 30, 2002, JCP&L had the
capability to issue up to $357.5 million of additional FMBs on the basis of
retired bonds. Based upon applicable earnings coverage tests and its charter,
JCP&L could issue $303.1 million of preferred stock (assuming no additional debt
was issued) based on earnings through September 30, 2002.
76
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of JCP&L's full-time employees are eligible to
participate in these plans. In accordance with the provisions of the Employment
Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded
status of its pension plans annually to determine if additional funding is
necessary. FirstEnergy has pre-funded a portion of the future liabilities
related to its OPEB plans. Under the terms of its postretirement benefit plans,
FirstEnergy reserves the right to change, modify or terminate the plans. Its
pension plan funding policy is to contribute annually an amount that is in
accordance with the provisions of ERISA - no contributions have been required
since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate access
to capital resources through cash generated from operations and through existing
lines of credit to support necessary funding requirements based on anticipated
plan performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, JCP&L would
be required to record an after-tax charge to equity (other comprehensive income)
of approximately $27 million in the fourth quarter of 2002 to recognize its
additional minimum pension liability of $46 million. The amount recorded will
depend upon the financial markets and interest rates in the remainder of 2002.
In addition, pension and other postretirement costs could increase by as much as
$30 million in 2003 based on the reduction of plan assets through October 31,
2002, due to adverse equity market conditions, lower rate of return assumptions
and the amortization of unrecognized losses, as well as higher health care trend
rates for OPEB (see Significant Accounting Policies - Pension and Other
Postretirement Benefits Accounting).
Market Risk Information
- -----------------------
JCP&L uses various market sensitive instruments, including derivative
contracts, primarily to manage the risk of price fluctuations. JCP&L's Risk
Policy Committee, comprised of FirstEnergy executive officers, exercises an
independent risk oversight function to ensure compliance with corporate risk
management policies and prudent risk management practices.
Commodity Price Risk
JCP&L is exposed to market risk primarily due to fluctuations in
electricity and natural gas prices. To manage the volatility relating to these
exposures, JCP&L uses a variety of derivative instruments, including forward
contracts, options and futures contracts. The derivatives are used for hedging
purposes. The change in the fair value of commodity derivative contracts related
to energy production during the third quarter of 2002 is summarized in the
following table:
Change in the Fair Value of Commodity Derivative Contracts
----------------------------------------------------------
(In millions)
Outstanding net asset as of June 30, 2002.............. $ 6.1
Increase in value of existing contracts................ 1.0
Change in techniques/assumptions....................... --
Settled contracts...................................... (0.4)
-----
Outstanding net asset as of September 30, 2002......... $ 6.7
=====
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, JCP&L relies on model-based information. The
model provides estimates of future regional prices for electricity and an
estimate of related price volatility. JCP&L utilizes these results in developing
estimates of fair value for the later years of applicable electricity contracts
for both 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:
77
Source of Information - Fair Value by Contract Year
---------------------------------------------------
2002* 2003 2004 Thereafter Total
----- ---- ---- ---------- -----
(In millions)
Prices actively quoted...... $-- $-- $-- $ -- $ --
Prices based on models**.... -- -- -- 6.7 6.7
--- --- --- ---- ----
Total..................... $-- $-- $-- $6.7 $6.7
=== === === ==== ====
* For the last quarter of 2002.
** Relates to an embedded option that is offset by a regulatory liability
and does not affect earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the
market risk of its commodity position. A hypothetical 10% adverse shift in
quoted market prices in the near term on derivative instruments would not have
had a material effect on JCP&L's consolidated financial position or cash flows
as of September 30, 2002.
New Jersey Regulatory Matters
- -----------------------------
On August 1, 2002, JCP&L submitted two rate filings with the New
Jersey Board of Public Utilities (NJBPU). The first filing is a request to
increase base electric rates by $98 million annually, an average of 5%. The
second filing is a request to recover deferred costs associated with mandated
purchase-power contracts with non-utility generators and providing Basic
Generation Service to customers in excess of the state's generation rate cap. As
of September 30, 2002, the accumulated deferred cost balance totaled
approximately $482 million. The deferral filing would result in an additional
2.8% increase in rates, assuming the use of securitization. The securitization
methodology is similar to the Oyster Creek securitization completed in May 2002.
The NJBPU has directed the Office of Administrative Law to have its
Administrative Law Judge issue a recommended decision by May 1, 2003; the Judge
has indicated she would request an extension. The rates established in this
proceeding will become effective August 1, 2003.
Environmental Matters
- ---------------------
JCP&L has been named as a "potentially responsible party" (PRP) 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 September 30, 2002, based on estimates of the
total costs of cleanup, JCP&L's 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 through the Societal
Benefits Charge. JCP&L has accrued liabilities aggregating approximately $50.7
million as of September 30, 2002. JCP&L does not believe environmental
remediation costs will have a material adverse effect on its financial
condition, cash flows or results of operations.
Significant Accounting Policies
- -------------------------------
JCP&L prepares its 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 JCP&L's assets
are subject to their own specific risks and uncertainties and are regularly
reviewed for impairment. JCP&L's goodwill will be reviewed for impairment at
least annually in accordance with SFAS 142. JCP&L's annual review was completed
in the third quarter of 2002 - the results of that review indicated no
impairment of goodwill. Other assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting these specific factors.
Purchase Accounting - Acquisition of GPU
On November 7, 2001, the merger between FirstEnergy and GPU became
effective, and JCP&L became a wholly owned subsidiary of FirstEnergy. The merger
was accounted for by the purchase method of accounting, which 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 were based primarily
on estimates. The adjustments reflected in JCP&L's records, which are subject to
adjustment in 2002 when finalized, primarily consist of: (1) revaluation of
certain property, plant and equipment; (2) adjusting preferred stock subject to
mandatory redemption and long-term debt to estimated fair value; (3) recognizing
additional obligations related to retirement benefits; and (4) recognizing
estimated severance and other compensation liabilities. The excess of the
purchase price over
78
the estimated fair values of the assets acquired and liabilities assumed was
recognized as goodwill, which totaled $1.9 billion at September 30, 2002.
Regulatory Accounting
JCP&L is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on costs that the regulatory agencies
determine JCP&L is 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 New Jersey, a significant amount of regulatory
assets have been recorded - $3.2 billion as of September 30, 2002. JCP&L
regularly reviews 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. JCP&L continually monitors its derivative contracts to determine if
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, JCP&L enters into commodity contracts,
which increase the impact of derivative accounting judgments.
Revenue Recognition
JCP&L follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," JCP&L periodically evaluates its 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 impairment must
be recognized in the financial statements. If impairment other than of a
temporary nature has occurred, JCP&L recognizes a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
79
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.
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced from the current assumed rate, pension and OPEB
liabilities and costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, return on plan assets has been (5.5%), (0.3%)
and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, JCP&L's reported pension costs would
increase. While OPEB plan assets have also been affected by sharp declines in
the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased which could affect
future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholder's equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods if
the fair value of trust assets exceeds the accumulated benefit obligation. The
amount of pension liability to be recorded as of December 31, 2002 will depend
upon the assumed discount rate (and any other change in FirstEnergy's
assumptions) and actual asset returns experienced in 2002.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time they are incurred rather
than when management commits to a plan of exit or disposal. It also requires the
use of fair value for the measurement of such liabilities. The new standard
supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This
new standard will be 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.
80
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $281,540 | $283,519 $767,333 | $727,075
-------- | -------- -------- | --------
| |
OPERATING EXPENSES AND TAXES: | |
Purchased power........................................ 201,320 | 164,313 483,756 | 417,915
Other operating costs.................................. 24,372 | 33,144 86,947 | 99,984
-------- | -------- -------- | --------
Total operation and maintenance expenses........... 225,692 | 197,457 570,703 | 517,899
Provision for depreciation and amortization............ 22,022 | 21,554 52,360 | 60,783
General taxes.......................................... 19,237 | 12,713 50,964 | 33,946
Income taxes........................................... 988 | 16,548 22,886 | 30,122
-------- | -------- -------- | --------
Total operating expenses and taxes................. 267,939 | 248,272 696,913 | 642,750
-------- | -------- -------- | --------
| |
OPERATING INCOME.......................................... 13,601 | 35,247 70,420 | 84,325
| |
OTHER INCOME.............................................. 5,884 | 2,618 16,471 | 12,620
-------- | -------- -------- | --------
| |
INCOME BEFORE NET INTEREST CHARGES........................ 19,485 | 37,865 86,891 | 96,945
-------- | -------- -------- | --------
| |
NET INTEREST CHARGES: | |
Interest on long-term debt............................. 10,054 | 10,558 30,736 | 28,867
Allowance for borrowed funds used during construction.. (234) | (305) (798) | (491)
Deferred interest...................................... (167) | (646) (402) | (646)
Other interest expense................................. 854 | 1,897 2,025 | 7,270
Subsidiaries' preferred stock dividend requirements.... 1,890 | 1,837 5,669 | 5,512
-------- | -------- -------- | --------
Net interest charges............................... 12,397 | 13,341 37,230 | 40,512
-------- | -------- -------- | --------
| |
NET INCOME................................................ $ 7,088 | $ 24,524 $ 49,661 | $ 56,433
======== | ======== ======== | ========
The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
81
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,640,974 $1,609,974
Less-Accumulated provision for depreciation............................... 564,051 530,006
---------- ----------
1,076,923 1,079,968
Construction work in progress-
Electric plant.......................................................... 11,783 14,291
---------- ----------
1,088,706 1,094,259
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 154,435 157,699
Long-term notes receivable from associated companies...................... 12,418 12,418
Other..................................................................... 27,147 13,391
---------- ----------
194,000 183,508
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 21,327 25,274
Receivables-
Customers (less accumulated provisions of $10,981,000 and $12,271,000,
respectively, for uncollectible accounts)............................. 121,822 112,257
Associated companies.................................................... 13,474 8,718
Other................................................................... 19,657 16,675
Prepayments and other..................................................... 7,575 12,239
---------- ----------
183,855 175,163
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 1,183,325 1,320,412
Goodwill.................................................................. 862,386 784,443
Other..................................................................... 43,649 49,402
---------- ----------
2,089,360 2,154,257
---------- ----------
$3,555,921 $3,607,187
========== ==========
82
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares -
859,500 shares outstanding............................................ $1,278,909 $1,274,325
Accumulated other comprehensive income (loss)........................... (37) 11
Retained earnings....................................................... 39,848 14,617
---------- ----------
Total common stockholder's equity................................... 1,318,720 1,288,953
Company-obligated trust preferred securities.............................. 92,357 92,200
Long-term debt............................................................ 540,002 583,077
---------- ----------
1,951,079 1,964,230
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 60,032 30,029
Accounts payable-
Associated companies.................................................... 47,197 67,351
Other................................................................... 27,411 36,750
Notes payable to associated companies..................................... 131,780 72,011
Accrued taxes............................................................. 1,953 7,037
Accrued interest.......................................................... 10,841 17,468
Other..................................................................... 10,413 13,652
---------- ----------
289,627 244,298
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 271,554 300,438
Accumulated deferred investment tax credits............................... 12,674 13,310
Purchase power contract loss liability.................................... 676,022 730,662
Nuclear fuel disposal costs............................................... 37,395 36,906
Nuclear plant decommissioning costs....................................... 272,680 268,967
Other..................................................................... 44,890 48,376
---------- ----------
1,315,215 1,398,659
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$3,555,921 $3,607,187
========== ==========
The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance
sheets.
83
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ----------------------
2002 2001 2002 2001
-------- --------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 7,088 | $ 24,524 $ 49,661 | $ 56,433
Adjustments to reconcile net income to net | |
cash from operating activities- | |
Provision for depreciation and amortization........ 22,022 | 21,554 52,360 | 60,783
Other amortization................................. (546) | 249 (1,940) | 1,005
Deferred costs, net................................ 7,678 | (74,600) (1,733) | (98,994)
Deferred income taxes, net......................... (1,841) | 34,101 10,349 | 44,978
Investment tax credits, net........................ (212) | (212) (636) | (636)
Receivables........................................ (3,494) | 34,773 (17,302) | 20,627
Accounts payable................................... (26,567) | (112,430) (29,492) | (54,684)
Accrued taxes...................................... 5 | (12,607) (5,084) | (13,177)
Other.............................................. (5,189) | (11,071) (37,056) | (43,904)
-------- | --------- -------- | --------
Net cash provided from (used for) operating | |
activities ..................................... (1,056) | (95,719) 19,127 | (27,569)
-------- | --------- -------- | --------
| |
CASH FLOWS FROM FINANCING ACTIVITIES: | |
New Financing- | |
Long-term debt....................................... -- | 48,100 49,750 | 99,500
Short-term borrowings, net........................... 60,628 | 13,400 59,769 | 13,400
Redemptions and Repayments- | |
Long-term debt....................................... 30,000 | -- 60,000 | --
Dividend Payments- | |
Common stock......................................... -- | -- 30,000 | 15,000
-------- | --------- -------- | --------
Net cash provided from financing activities...... 30,628 | 61,500 19,519 | 97,900
-------- | --------- -------- | --------
| |
CASH FLOWS FROM INVESTING ACTIVITIES: | |
Property additions..................................... 11,209 | 12,592 31,996 | 37,614
Decommissioning trust investments...................... 2,371 | 2,371 10,358 | 7,113
Other.................................................. -- | 446 239 | 5,001
-------- | --------- -------- | --------
Net cash used for investing activities........... 13,580 | 15,409 42,593 | 49,728
-------- | --------- -------- | --------
| |
Net increase (decrease) in cash and cash equivalents...... 15,992 | (49,628) (3,947) | 20,603
Cash and cash equivalents at beginning of period.......... 5,335 | 73,670 25,274 | 3,439
-------- | --------- -------- | --------
Cash and cash equivalents at end of period................ $ 21,327 | $ 24,042 $ 21,327 | $ 24,042
======== | ========= ======== | ========
The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
84
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of Metropolitan
Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan
Edison Company and its subsidiaries as of September 30, 2002, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 30, 2002. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
85
METROPOLITAN EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy.
Met-Ed conducts business in the eastern and south central portions of
Pennsylvania, offering regulated electric transmission and distribution
services. Met-Ed also provides power to those customers electing to retain them
as their power supplier. Met-Ed's regulatory plan itemizes, or unbundles, the
price of electricity into its component elements - including generation,
transmission, distribution and transition charges. Met-Ed was formerly a wholly
owned subsidiary of GPU, Inc., which merged with FirstEnergy on November 7,
2001.
In September 2002, Met-Ed established a reserve of $143.2 million for
its PLR deferred energy costs (see Pennsylvania Regulatory Matters). The reserve
reflects the potential adverse impact of a pending Pennsylvania Supreme Court
decision whether to review the Commonwealth Court ruling. In the interim
financial statements in 2002, Met-Ed had previously disclosed, in consultation
with its independent accountants, that the finalization of that potential
pre-acquisition contingency relating to the FirstEnergy/GPU merger would be
reflected as an adjustment to the allocation of the purchase price prior to the
end of the third quarter of 2002. In connection with FirstEnergy finalizing the
purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter
of 2002, Met-Ed after further consultation with its independent accountants,
revised the previously disclosed accounting for this potential pre-acquisition
contingency. This resulted in the recognition of a reserve related to deferred
energy costs of $112.5 million as an increase to goodwill and a $30.7 million
pre-tax charge related to deferred energy costs subsequent to the acquisition
date in the income statement in the periods in which these costs were incurred.
Accordingly, Met-Ed will be amending its interim consolidated financial
statements included in its Form 10-Q filings for the quarters ended March 31,
2002 and June 30, 2002 (see Financial Statement Revision). The consolidated
financial statements for the three-month and nine-month periods ended September
30, 2002 reflect the effect of the retroactive application.
Results of Operations
- ---------------------
Operating revenues decreased by $2.0 million or 0.7% in the third
quarter of 2002, and increased $40.3 million or 5.5% in the first nine months of
2002, compared to the same periods in 2001. The sources of the changes in
operating revenues, as compared to the same periods in 2001, are summarized in
the following table.
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Change in kilowatt-hour sales due to level of retail
customers shopping for generation service........... $(15.2) $ 41.6
Change in other retail kilowatt-hour sales............. 29.8 29.1
Change in wholesale sales.............................. (17.5) (27.2)
All other changes...................................... 0.9 (3.2)
------ ------
Net Increase (Decrease) in Operating Revenues.......... $ (2.0) $ 40.3
====== ======
Electric Sales
During the first half of 2002, Met-Ed had experienced a significant
reduction in the number of customers who received their power from alternate
suppliers, which had a positive effect on operating revenues. However, during
the third quarter of 2002, this trend reversed slightly as more industrial and
commercial customers shopped for power, which resulted in a decrease in
operating revenues during that period. Warmer weather during the third quarter
of 2002, compared to third quarter of 2001, contributed to an increase in retail
distribution deliveries. Partially offsetting this increase in revenues were
lower sales to industrial customers due to a decline in economic conditions, as
well as reduced revenues from wholesale customers. Changes in kilowatt-hour
deliveries by customer class during the three and nine month periods ended
September 30, 2002, as compared to the same periods in 2001, are summarized in
the following table:
86
Changes in Distribution Deliveries
and Wholesale Generation Sales
------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Residential............................. 13.0 % 2.0 %
Commercial.............................. 3.6 % 2.0 %
Industrial.............................. (0.9)% (4.7)%
----- -----
Total Retail....................... 5.5 % (0.2)%
Wholesale............................... (37.9)% (13.4)%
----- -----
Total................................... 0.6 % (1.4)%
===== =====
Operating Expenses and Taxes
Total operating expenses and taxes increased $19.7 million in the
third quarter of 2002, and $54.2 million in the first nine months of 2002,
compared to the same periods in 2001. A majority of the increase in both periods
was due to higher purchased power costs, as Met-Ed required additional power to
satisfy its provider of last resort (PLR) obligation to customers who returned
from alternate suppliers in the first nine months of 2002. In addition, the
establishment of a reserve reflecting the potential adverse impact of a pending
Pennsylvania Supreme Court decision resulted in a 2002 charge to purchased power
costs. (See Pennsylvania Regulatory Matters for further discussion.) Other
operating costs decreased $8.8 million and $13.0 million in the quarter and nine
months ended September 30, 2002, respectively, compared to the same periods in
2001. The decreases were due primarily to the absence of costs related to early
retirement programs offered to certain bargaining unit employees in the first
quarter of 2001, the absence of other 2001 employee costs and the absence of
costs related to the use of portable generators at certain substations under a
pilot program during the third quarter of 2001, partially offset by higher
rental and pension costs. General taxes increased $6.5 million and $17.0 million
in the quarter and nine months ended September 30, 2002, respectively, compared
to the same periods in 2001, due primarily to an increase in Pennsylvania gross
receipts taxes.
Other Income
Other income increased $3.3 million in the third quarter of 2002, and
$3.9 million in the first nine months of 2002, compared to the same periods in
2001, primarily due to the absence in 2002 of net losses incurred in 2001 on
futures contracts and options, and increased contract work in the third quarter
of 2002.
Net Interest Charges
Net interest charges decreased $0.9 million in the third quarter of
2002, and $3.3 million in the first nine months of 2002, compared to the same
periods in 2001, primarily due to reduced short-term borrowing levels and
amortization of fair value adjustments recorded in connection with the merger.
Interest expense was further reduced by the redemption of $30 million of notes
in the first quarter of 2002; however, that reduction was partially offset by
the issuance of $100 million of notes in September 2001 and $50 million of notes
in May 2002 (used to refinance $30 million of notes in July 2002).
Financial Statements Revision
During the third quarter of 2002, Met-Ed established a reserve and
recorded a non-cash charge of $30.7 million ($17.9 million net of tax) for
deferred energy costs incurred subsequent to the merger (see Pennsylvania
Regulatory Matters). The reserve reflects the potential adverse impact of a
pending Pennsylvania Supreme Court decision whether to review the Commonwealth
Court ruling. In the interim financial statements in 2002, Met-Ed had previously
disclosed, in consultation with its independent accountants, that the
finalization of that potential pre-acquisition contingency relating to the
FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of
the purchase price prior to the end of the third quarter of 2002. In connection
with FirstEnergy finalizing the purchase accounting relating to the
FirstEnergy/GPU merger, in the third quarter of 2002, Met-Ed after further
consultation with its independent accountants, revised the previously disclosed
accounting for this potential pre-acquisition contingency. This resulted in the
recognition of a reserve related to deferred energy costs of $112.5 million as
an increase to goodwill and a $30.7 million pre-tax charge related to deferred
energy costs subsequent to the acquisition date in the income statement in the
periods in which these costs were incurred. Accordingly, Met-Ed will be amending
its interim consolidated financial statements included in its Form 10-Q filings
to reflect the redistributed earnings impact of the $30.7 million for the
quarters ended March 31, 2002 and June 30, 2002. (see Note 4). The reserve for
the $112.5 million of deferred energy costs as of the acquisition date increased
goodwill by $65.8 million, net of tax. Should the Pennsylvania Supreme Court
ultimately uphold FirstEnergy's appeal, the $30.7 million charge would be
reversed into earnings.
87
Capital Resources and Liquidity
- -------------------------------
Met-Ed has continuing cash requirements for planned capital
expenditures, which are expected to be about $20.0 million during the remaining
three months of 2002. These requirements are expected to be satisfied from
internal cash and/or short-term credit arrangements.
As of September 30, 2002, Met-Ed had about $21.3 million of cash and
temporary investments and $131.8 million of short-term indebtedness. Met-Ed may
borrow from its affiliates on a short-term basis. Met-Ed will not issue first
mortgage bonds (FMBs) other than as collateral for senior notes, since its
senior note indenture prohibits (subject to certain exceptions) it from issuing
any debt which is senior to the senior notes. As of September 30, 2002, Met-Ed
had the capability to issue up to $118.3 million of additional FMBs on the basis
of property additions and retired bonds. Met-Ed has no restrictions on the
issuance of preferred stock.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of Met-Ed's full-time employees are eligible to
participate in these plans. In accordance with the provisions of the Employment
Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded
status of its pension plans annually to determine if additional funding is
necessary. FirstEnergy has pre-funded a portion of the future liabilities
related to its OPEB plans. Under the terms of its postretirement benefit plans,
FirstEnergy reserves the right to change, modify or terminate the plans. Its
pension plan funding policy is to contribute annually an amount that is in
accordance with the provisions of ERISA - no contributions have been required
since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate access
to capital resources through cash generated from operations and through existing
lines of credit to support necessary funding requirements based on anticipated
plan performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, Met-Ed
would be required to record an after-tax charge to equity (other comprehensive
income) of approximately $23 million in the fourth quarter of 2002 to recognize
its additional minimum pension liability of $39 million. The amount recorded
will depend upon the financial markets and interest rates in the remainder of
2002. In addition, pension and other postretirement costs could increase by as
much as $12 million in 2003 based on the reduction of plan assets through
October 31, 2002, due to adverse equity market conditions, lower rate of return
assumptions and the amortization of unrecognized losses, as well as higher
health care trend rates for OPEB (see Significant Accounting Policies - Pension
and Other Postretirement Benefits Accounting).
Market Risk Information
- -----------------------
Met-Ed uses various market sensitive instruments, including
derivative contracts, primarily to manage the risk of price fluctuations.
Met-Ed's Risk Policy Committee, comprised of FirstEnergy executive officers,
exercises an independent risk oversight function to ensure compliance with
corporate risk management policies and prudent risk management practices.
Commodity Price Risk
Met-Ed is exposed to market risk primarily due to fluctuations in
electricity and natural gas prices. To manage the volatility relating to these
exposures, Met-Ed uses a variety of derivative instruments, including options
and futures contracts. The derivatives are used for hedging purposes. The change
in the fair value of commodity derivative contracts related to energy production
during the third quarter of 2002 is summarized in the following table:
Change in the Fair Value of Commodity Derivative Contracts
----------------------------------------------------------
(In millions)
Outstanding net asset as of June 30, 2002........... $11.3
Increase in value of existing contracts............. 2.0
Change in techniques/assumptions.................... --
Settled contracts................................... 0.1
-----
Outstanding net asset as of September 30, 2002...... $13.4
=====
88
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, Met-Ed relies on model-based information. The
model provides estimates of future regional prices for electricity and an
estimate of related price volatility. Met-Ed utilizes these results in
developing estimates of fair value for the later years of applicable electricity
contracts 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:
Source of Information - Fair Value by Contract Year
- ---------------------------------------------------
2002* 2003 2004 Thereafter Total
----- ---- ---- ---------- -----
(In millions)
Prices actively quoted...... $-- $0.1 $-- $ -- $ 0.1
Prices based on models**.... -- -- -- 13.3 13.3
--- ---- --- ----- -----
Total..................... $-- $0.1 $-- $13.3 $13.4
=== ==== === ===== =====
* For the last quarter of 2002.
** Relates to an embedded option that is offset by a regulatory liability
and does not affect earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the
market risk of its commodity position. A hypothetical 10% adverse shift in
quoted market prices in the near term on derivative instruments would not have
had a material effect on Met-Ed's consolidated financial position or cash flows
as of September 30, 2002.
Pennsylvania Regulatory Matters
- -------------------------------
In June and July 2001, several parties had filed Petitions for Review
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders
which approved the FirstEnergy/GPU merger and provided rate relief for Met-Ed.
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
Met-Ed's PLR obligation, and rejected those parts of the settlement that
permitted the Company to defer for accounting purposes the difference between
its wholesale power costs and the amount collected from retail customers. Met-Ed
and 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's
decision. Also on March 25, 2002, Citizens Power filed a motion seeking an
appeal of the Commonwealth Court's decision to affirm the FirstEnergy/GPU merger
with the Supreme Court of Pennsylvania. In September 2002, Met-Ed established a
reserve of $143.2 million for its PLR deferred energy costs. The reserve
reflects the potential adverse impact of a pending Pennsylvania Supreme Court
decision whether to review the Commonwealth Court ruling. Met-Ed recorded a
non-cash charge of $30.7 million ($17.9 million net of tax) for the deferred
energy costs incurred subsequent to the merger. The reserve for the remaining
$112.5 million of deferred costs increased Met-Ed's goodwill by the net of tax
amount of $65.8 million.
Significant Accounting Policies
- -------------------------------
Met-Ed prepares its 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 Met-Ed's assets
are subject to their own specific risks and uncertainties and are regularly
reviewed for impairment. Met-Ed's goodwill will be reviewed for impairment at
least annually in accordance with SFAS 142. Met-Ed's annual review was completed
in the third quarter of 2002 - the results of that review indicated no
impairment of goodwill. Other assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting these specific factors.
89
Purchase Accounting - Acquisition of GPU
On November 7, 2001, the merger between FirstEnergy and GPU became
effective, and Met-Ed became a wholly owned subsidiary of FirstEnergy. The
merger was accounted for by the purchase method of accounting, which 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 were
based primarily on estimates. The adjustments reflected in Met-Ed's records,
which are subject to adjustment in 2002 when finalized, primarily consist of:
(1) revaluation of certain property, plant and equipment; (2) adjusting
preferred stock subject to mandatory redemption and long-term debt to estimated
fair value; (3) recognizing additional obligations related to retirement
benefits; and (4) recognizing estimated severance and other compensation
liabilities. The excess of the purchase price over the estimated fair values of
the assets acquired and liabilities assumed was recognized as goodwill, which
totaled $862.4 million at September 30, 2002.
89
Regulatory Accounting
Met-Ed is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on costs that the regulatory agencies
determine Met-Ed is 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 Pennsylvania, a significant amount of
regulatory assets have been recorded - $1.2 billion as of September 30, 2002.
Met-Ed regularly reviews 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. In September 2002, Met-Ed established a $143.2 million
reserve, reflecting the current estimate of potential adverse impact in a
pending Pennsylvania Supreme Court decision. (See Pennsylvania Regulatory
Matters for further discussion.)
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. Met-Ed continually monitors its derivative contracts to determine if
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, Met-Ed enters into commodity contracts,
which increase the impact of derivative accounting judgments.
Revenue Recognition
Met-Ed follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," Met-Ed periodically evaluates its 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 impairment must
be recognized in the financial statements. If impairment other than of a
temporary nature has occurred, Met-Ed recognizes a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
90
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.
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced from the current assumed rate, pension and OPEB
liabilities and costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, return on plan assets has been (5.5%), (0.3%)
and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, Met-Ed's reported pension costs would
increase. While OPEB plan assets have also been affected by sharp declines in
the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased which could affect
future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholder's equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods if
the fair value of trust assets exceeds the accumulated benefit obligation. The
amount of pension liability to be recorded as of December 31, 2002 will depend
upon the assumed discount rate (and any other change in FirstEnergy's
assumptions) and actual asset returns experienced in 2002.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. 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 various applicable legal obligations
as defined under the new standard and expects to complete an analysis of their
financial impact in the fourth quarter of 2002.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time they are incurred rather
than when management commits to a plan of exit or disposal. It also requires the
use of fair value for the measurement of such liabilities. The new standard
supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This
new standard will be 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.
91
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $269,359 | $265,603 $749,755 | $740,030
-------- | -------- -------- | --------
| |
| |
OPERATING EXPENSES AND TAXES: | |
Purchased power........................................ 191,756 | 163,968 480,608 | 475,359
Other operating costs.................................. 27,759 | 33,602 99,977 | 114,367
-------- | -------- -------- | --------
Total operation and maintenance expenses........... 219,515 | 197,570 580,585 | 589,726
Provision for depreciation and amortization............ 16,098 | 13,674 45,743 | 43,302
General taxes.......................................... 17,744 | 12,486 47,200 | 36,637
Income taxes........................................... 3,040 | 15,104 18,839 | 16,406
-------- | -------- -------- | --------
Total operating expenses and taxes................. 256,397 | 238,834 692,367 | 686,071
-------- | -------- -------- | --------
| |
OPERATING INCOME.......................................... 12,962 | 26,769 57,388 | 53,959
| |
OTHER INCOME (EXPENSE).................................... 1,067 | (1,234) 2,154 | 785
-------- | -------- -------- | --------
| |
INCOME BEFORE NET INTEREST CHARGES........................ 14,029 | 25,535 59,542 | 54,744
-------- | -------- -------- | --------
| |
NET INTEREST CHARGES: | |
Interest on long-term debt............................. 7,796 | 8,735 24,124 | 25,154
Allowance for borrowed funds used during construction.. 84 | 224 (199) | (60)
Deferred interest...................................... (869) | (592) (2,311) | (592)
Other interest expense................................. 684 | 956 2,123 | 5,275
Subsidiaries' preferred stock dividend requirements.... 1,888 | 1,835 5,665 | 5,505
-------- | -------- -------- | --------
Net interest charges............................... 9,583 | 11,158 29,402 | 35,282
-------- | -------- -------- | --------
| |
NET INCOME................................................ $ 4,446 | $ 14,377 $ 30,140 | $ 19,462
======== | ======== ======== | ========
The preceding Notes to Financial Statements as they relate to Pennsylvania
Electric Company are an integral part of these statements.
92
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,873,598 $1,845,187
Less-Accumulated provision for depreciation............................... 668,941 630,957
---------- ----------
1,204,657 1,214,230
Construction work in progress -
electric plant ......................................................... 9,872 12,857
---------- ----------
1,214,529 1,227,087
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Non-utility generation trusts............................................. 123,658 154,067
Nuclear plant decommissioning trusts...................................... 89,274 96,610
Long-term notes receivable from associated companies...................... 15,515 15,515
Other..................................................................... 7,595 2,265
---------- ----------
236,042 268,457
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 32,310 39,033
Receivables-
Customers (less accumulated provisions of $11,849,000 and $14,719,000,
respectively, for uncollectible accounts)............................. 93,780 107,170
Associated companies.................................................... 52,349 40,203
Other................................................................... 16,551 14,842
Prepayments and other..................................................... 6,509 8,605
---------- ----------
201,499 209,853
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 574,290 769,807
Goodwill.................................................................. 873,600 797,362
Accumulated deferred income taxes......................................... 26,764 --
Other..................................................................... 24,057 27,703
---------- ----------
1,498,711 1,594,872
---------- ----------
$3,150,781 $3,300,269
========== ==========
93
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, par value $20 per share, authorized 5,400,000
shares, 5,290,596 shares outstanding.................................. $ 105,812 $ 105,812
Other paid-in capital................................................... 1,192,849 1,188,190
Accumulated other comprehensive income.................................. 428 1,779
Retained earnings....................................................... 31,437 10,795
---------- ----------
Total common stockholder's equity................................... 1,330,526 1,306,576
Company-obligated trust preferred securities ............................. 92,160 92,000
Long-term debt............................................................ 470,950 472,400
---------- ----------
1,893,636 1,870,976
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 25,798 50,756
Accounts payable-
Associated companies.................................................... 121,360 126,390
Other................................................................... 28,179 38,720
Notes payable to associated companies..................................... 103,932 77,623
Accrued taxes............................................................. 6,286 29,255
Accrued interest.......................................................... 18,662 12,284
Other..................................................................... 7,885 10,993
---------- ----------
312,102 346,021
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... -- 21,682
Accumulated deferred investment tax credits............................... 11,100 11,956
Nuclear plant decommissioning costs....................................... 137,364 135,483
Nuclear fuel disposal costs............................................... 18,697 18,453
Power purchase contract loss liability.................................... 750,941 867,046
Other..................................................................... 26,941 28,652
---------- ----------
945,043 1,083,272
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$3,150,781 $3,300,269
========== ==========
The preceding Notes to Financial Statements as they relate to Pennsylvania
Electric Company are an integral part of these balance sheets.
94
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- --------- -------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net income................................................ $ 4,446 | $ 14,377 $ 30,140 | $ 19,462
Adjustments to reconcile net income to net | |
cash from operating activities- | |
Provision for depreciation and amortization........ 16,098 | 13,674 45,743 | 43,302
Other amortization................................. (70) | 449 117 | 1,493
Deferred costs, net................................ (13,468) | (91,802) (41,168) | (126,557)
Deferred income taxes, net......................... 4,525 | 34,330 3,087 | 43,212
Investment tax credits, net........................ (285) | (285) (856) | (856)
Receivables........................................ 9,186 | (42,777) (466) | (33,276)
Accounts payable................................... (16,663) | 21,448 (15,570) | 64,528
Accrued taxes...................................... (3,144) | 882 (22,969) | (4,762)
Other.............................................. 21,888 | (11,629) 7,689 | (22,600)
-------- | --------- -------- | ---------
Net cash provided from (used for) operating | |
activities ..................................... 22,513 | (61,333) 5,747 | (16,054)
-------- | --------- -------- | ---------
| |
CASH FLOWS FROM FINANCING ACTIVITIES: | |
New Financing- | |
Short-term borrowings, net........................... 444 | -- 26,309 | 9,200
Contributions from parent............................ -- | -- -- | 50,000
Redemptions and Repayments- | |
Long-term debt....................................... -- | -- 24,973 | --
Short-term borrowings, net........................... -- | 44,000 -- | --
Dividend Payments- | |
Common stock......................................... -- | -- 14,000 | --
-------- | --------- -------- | ---------
Net cash used for (provided from) financing | |
activities ..................................... (444) | 44,000 12,664 | (59,200)
-------- | --------- -------- | ---------
| |
CASH FLOWS FROM INVESTING ACTIVITIES: | |
Property additions..................................... 10,958 | 8,157 33,775 | 37,529
Proceeds from non-utility generation trusts............ -- | (2,154) (34,208) | (18,339)
Decommissioning trust investments...................... -- | -- -- | 15
Other.................................................. -- | 801 239 | 4,972
-------- | --------- -------- | ---------
Net cash used for (provided from) investing | |
activities ..................................... 10,958 | 6,804 (194) | 24,177
-------- | --------- -------- | ---------
| |
Net increase (decrease) in cash and cash equivalents...... 11,999 | (112,137) (6,723) | 18,969
Cash and cash equivalents at beginning of period.......... 20,311 | 131,686 39,033 | 580
-------- | --------- -------- | ---------
Cash and cash equivalents at end of period................ $ 32,310 | $ 19,549 $ 32,310 | $ 19,549
======== | ========= ======== | =========
The preceding Notes to Financial Statements as they relate to Pennsylvania
Electric Company are an integral part of these statements.
95
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Shareholders of Pennsylvania
Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania
Electric Company and its subsidiaries as of September 30, 2002, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 30, 2002. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 13, 2002
96
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Penelec is a wholly owned electric utility subsidiary of FirstEnergy.
Penelec conducts business in northern, western, and south central portions of
Pennsylvania, offering regulated electric transmission and distribution
services. Penelec also provides power to those customers electing to retain them
as their power supplier. Penelec's regulatory plan itemizes, or unbundles, the
price of electricity into its component elements - including generation,
transmission, distribution and transition charges. Penelec was formerly a wholly
owned subsidiary of GPU, Inc., which merged with FirstEnergy on November 7,
2001.
In September 2002, Penelec established a reserve of $143.9 million for
its PLR deferred energy costs (see Pennsylvania Regulatory Matters). The reserve
reflects the potential adverse impact of a pending Pennsylvania Supreme Court
decision whether to review the Commonwealth Court ruling. In the interim
financial statements in 2002, Penelec had previously disclosed, in consultation
with its independent accountants, that the finalization of that potential
pre-acquisition contingency relating to the FirstEnergy/GPU merger would be
reflected as an adjustment to the allocation of the purchase price prior to the
end of the third quarter of 2002. In connection with FirstEnergy finalizing the
purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter
of 2002, Penelec after further consultation with its independent accountants,
revised the previously disclosed accounting for this potential pre-acquisition
contingency. This resulted in the recognition of a reserve related to deferred
energy costs of $118.8 million as an increase to goodwill and a $25.1 million
pre-tax charge related to deferred energy costs subsequent to the acquisition
date in the income statement in the periods in which these costs were incurred.
Accordingly, Penelec will be amending its interim consolidated financial
statements included in its Form 10-Q filings for the quarters ended March 31,
2002 and June 30, 2002 (see Financial Statement Revision). The consolidated
financial statements for the three-month and nine-month periods ended September
30, 2002 reflect the effect of the retroactive application.
Results of Operations
- ---------------------
Operating revenues increased by $3.7 million or 1.4% in the third
quarter of 2002, and $9.7 million or 1.3% in the first nine months of 2002,
compared to the same periods in 2001. The sources of the changes in operating
revenues, as compared to the same periods in 2001, are summarized in the
following table.
Sources of Operating Revenue Changes
------------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Change in kilowatt-hour sales due to level of retail
customers shopping for generation service........... $ (1.9) $ 58.5
Change in other retail kilowatt-hour sales............. 19.3 10.5
Change in wholesale sales.............................. (12.3) (52.9)
All other changes...................................... (1.4) (6.4)
------- ------
Net Increase in Operating Revenues..................... $ 3.7 $ 9.7
====== ======
Electric Sales
In the first nine months of 2002, a reduction in the number of
customers who received their power from alternate suppliers continued to have a
positive effect on operating revenues. During the first nine months of 2001,
16.3% of kilowatt-hours delivered were to shopping customers, whereas only 5.4%
of kilowatt-hours delivered during the same period in 2002 were to shopping
customers. In addition, warmer weather in the third quarter of 2002 contributed
to an increase in retail distribution deliveries. Partially offsetting these
increases were lower sales to wholesale customers during the first nine months
of 2002. A decline in economic conditions resulted in a decrease in sales to
industrial customers for the nine months ended September 30, 2002; however,
economic conditions continued to improve during the third quarter of 2002,
resulting in a slight increase in industrial sales during that period. Changes
in kilowatt-hour deliveries by customer class during the three and nine month
periods ended September 30, 2002, as compared to the same periods in 2001, are
summarized in the following table:
97
Changes in Distribution Deliveries
and Wholesale Generation Sales
------------------------------
Increase (Decrease)
Periods Ending September 30, 2002
---------------------------------
3 Months 9 Months
-------- --------
(In millions)
Residential............................ 10.7% 2.4%
Commercial............................. 5.5% 2.5%
Industrial............................. 1.1% (2.9)%
----- -----
Total Retail...................... 5.5% 0.7%
Wholesale.............................. (45.8)% (65.5)%
----- -----
Total.................................. 0.3% (7.1)%
===== =====
Operating Expenses and Taxes
Total operating expenses and taxes increased $17.6 million and $6.3
million in the three and nine month periods ended September 30, 2002,
respectively, compared to the same periods in 2001. Purchased power costs
increased $27.8 million and $5.2 million in the third quarter of 2002 and the
nine months ended September 30, 2002, compared to the same periods in 2001.
Increases in purchased power costs were due primarily to the establishment of a
reserve reflecting the potential adverse impact of a pending Pennsylvania
Supreme Court decision, which resulted in a 2002 charge to purchased power
costs. (See Pennsylvania Regulatory Matters for further discussion.) These
increases were partially offset by a reduction in power purchased during the
third quarter of 2002, as well as by the absence in 2002 of a $16.0 million
charge related to the termination of a wholesale energy contract in 2001. Other
operating costs decreased $5.8 million and $14.4 million in the quarter and nine
months ended September 30, 2002, respectively, compared to the same periods in
2001. These decreases were due primarily to the absence of costs related to
early retirement programs offered to certain bargaining unit employees in the
first quarter of 2001, reduced other employee costs, and lower uncollectible
expenses in 2002. These decreases were offset by higher pension costs. General
taxes increased $5.3 million and $10.6 million in the quarter and nine months
ended September 30, 2002, respectively, compared to the same periods in 2001,
due primarily to an increase in Pennsylvania gross receipts taxes.
Net Interest Charges
Net interest charges decreased $1.6 million in the third quarter of
2002, and $5.9 million in the first nine months of 2002, compared to the same
periods in 2001, primarily due to higher interest deferrals related to Penelec's
deferred provider of last resort costs, as well as reduced short-term borrowing
levels and amortization of fair market value adjustments recorded in connection
with the merger.
Financial Statements Revision
During the third quarter of 2002, Penelec established a reserve and
recorded a non-cash charge of $25.1 million ($14.7 million net of tax) for
deferred energy costs incurred subsequent to the merger (see Pennsylvania
Regulatory Matters). The reserve reflects the potential adverse impact of a
pending Pennsylvania Supreme Court decision whether to review the Commonwealth
Court ruling. In the interim financial statements in 2002, Penelec had
previously disclosed, in consultation with its independent accountants, that the
finalization of that potential pre-acquisition contingency relating to the
FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of
the purchase price prior to the end of the third quarter of 2002. In connection
with FirstEnergy finalizing the purchase accounting relating to the
FirstEnergy/GPU merger, in the third quarter of 2002, Penelec after further
consultation with its independent accountants, revised the previously disclosed
accounting for this potential pre-acquisition contingency. This resulted in the
recognition of a reserve related to deferred energy costs of $118.8 million
as an increase to goodwill and a $25.1 million
pre-tax charge related to deferred energy costs subsequent to the acquisition
date in the income statement in the periods in which these costs were incurred.
Accordingly, Penelec will be amending its interim consolidated financial
statements included in its Form 10-Q filings to reflect the redistributed
earnings impact of the $25.1 million for the quarters ended March 31, 2002 and
June 30, 2002 (see Note 4). The reserve for the $118.8 million of deferred
energy costs as of the acquisition date increased goodwill by $69.5 million, net
of tax. Should the Pennsylvania Supreme Court ultimately uphold FirstEnergy's
appeal, the $25.1 million charge would be reversed into earnings.
Capital Resources and Liquidity
- -------------------------------
Penelec has continuing cash requirements for planned capital
expenditures and maturing debt. During the remaining three months of 2002,
capital requirements for property additions are expected to be about $20.0
million. Penelec also has requirements for maturing long-term debt of $25.2
million during the remainder of 2002. These requirements are expected to be
satisfied from internal cash and/or short-term credit arrangements.
98
As of September 30, 2002, Penelec had about $32.3 million of cash and
temporary investments and $103.9 million of short-term indebtedness. Penelec may
borrow from its affiliates on a short-term basis. Penelec will not issue first
mortgage bonds (FMBs) other than as collateral for senior notes, since its
senior note indenture prohibits (subject to certain exceptions) it from issuing
any debt which is senior to the senior notes. As of September 30, 2002, Penelec
had the capability to issue up to $462.9 million of additional FMBs on the basis
of property additions and retired bonds. Penelec has no restrictions on the
issuance of preferred stock.
Postretirement Plans
FirstEnergy maintains defined benefit pension plans, as well as
several other postretirement employee benefit (OPEB) plans such as health care
and life insurance. All of Penelec's full-time employees are eligible to
participate in these plans. In accordance with the provisions of the Employment
Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded
status of its pension plans annually to determine if additional funding is
necessary. FirstEnergy has pre-funded a portion of the future liabilities
related to its OPEB plans. Under the terms of its postretirement benefit plans,
FirstEnergy reserves the right to change, modify or terminate the plans. Its
pension plan funding policy is to contribute annually an amount that is in
accordance with the provisions of ERISA - no contributions have been required
since 1985.
Due to sharp declines in the equity markets in the United States
since the second quarter of 2000, the value of assets held in the trusts to
satisfy the obligations of pension plans has significantly decreased. As a
result, under the minimum funding requirements of ERISA or the Pension Benefit
Guaranty Corporation, FirstEnergy may be required to resume contributing to the
plan trusts as early as 2004. FirstEnergy believes that it has adequate access
to capital resources through cash generated from operations and through existing
lines of credit to support necessary funding requirements based on anticipated
plan performance. While OPEB plan assets have also been affected by the sharp
declines in the equity market, contributions are voluntary and declines have a
limited impact on required future funding.
If the market value of FirstEnergy's pension plan assets were to
remain unchanged from October 31, 2002, through the end of the year, Penelec
would be required to record an after-tax charge to equity (other comprehensive
income) of approximately $13 million in the fourth quarter of 2002 to recognize
its additional minimum pension liability of $21 million. The amount recorded
will depend upon the financial markets and interest rates in the remainder of
2002. In addition, pension and other postretirement costs could increase by as
much as $14 million in 2003 based on the reduction of plan assets through
October 31, 2002, due to adverse equity market conditions, lower rate of return
assumptions and the amortization of unrecognized losses, as well as higher
health care trend rates for OPEB (see Significant Accounting Policies - Pension
and Other Postretirement Benefits Accounting).
Market Risk Information
- -----------------------
Penelec uses various market sensitive instruments, including
derivative contracts, primarily to manage the risk of price fluctuations.
Penelec's Risk Policy Committee, comprised of FirstEnergy executive officers,
exercises an independent risk oversight function to ensure compliance with
corporate risk management policies and prudent risk management practices.
Commodity Price Risk
Penelec is exposed to market risk primarily due to fluctuations in
electricity and natural gas prices. To manage the volatility relating to these
exposures, Penelec uses a variety of derivative instruments, including options
and futures contracts. The derivatives are used for hedging purposes. The change
in the fair value of commodity derivative contracts related to energy production
during the third quarter of 2002 is summarized in the following table:
Change in the Fair Value of Commodity Derivative Contracts
----------------------------------------------------------
(In millions)
Outstanding net asset as of June 30, 2002.............. $5.7
Increase in value of existing contracts................ 1.0
Change in techniques/assumptions....................... ----
Settled contracts...................................... 0.1
----
Outstanding net asset as of September 30, 2002......... $6.8
====
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, Penelec relies on model-based information.
The model provides estimates of future regional prices for electricity and an
estimate of related price volatility. Penelec utilizes these results in
developing estimates of fair value for the later years of applicable electricity
contracts for both financial
99
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:
Source of Information - Fair Value by Contract Year
- ---------------------------------------------------
2002* 2003 2004 Thereafter Total
----- ---- ---- ---------- -----
(In millions)
Prices actively quoted... $-- $0.1 $-- $ -- $0.1
Prices based on models**. -- -- -- 6.7 6.7
--- ---- --- ---- ----
Total.................. $-- $0.1 $-- $6.7 $6.8
=== ==== === ==== ====
* For the last quarter of 2002.
** Relates to an embedded option that is offset by a regulatory liability
and does not affect earnings.
Penelec performs sensitivity analyses to estimate its exposure to the
market risk of its commodity position. A hypothetical 10% adverse shift in
quoted market prices in the near term on derivative instruments would not have
had a material effect on Penelec's consolidated financial position or cash flows
as of September 30, 2002.
Pennsylvania Regulatory Matters
- -------------------------------
In June and July 2001, several parties had filed Petitions for Review
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders
which approved the FirstEnergy/GPU merger and provided rate relief for Penelec.
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
Penelec's PLR obligation, and rejected those parts of the settlement that
permitted the Company to defer for accounting purposes the difference between
its wholesale power costs and the amount collected from retail customers.
Penelec and 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's decision. Also on March 25, 2002, Citizens Power filed a
motion seeking an appeal of the Commonwealth Court's decision to affirm the
FirstEnergy/GPU merger with the Supreme Court of Pennsylvania. In September
2002, Penelec established a reserve of $143.9 million for its PLR deferred
energy costs. The reserve reflects the potential adverse impact of a pending
Pennsylvania Supreme Court decision whether to review the Commonwealth Court
ruling. Penelec recorded a non-cash charge of $25.1 million ($14.7 million net
of tax) for the deferred energy costs incurred subsequent to the merger. The
reserve for the remaining $118.8 million of deferred costs increased Penelec's
goodwill by the net of tax amount of $69.5 million.
Significant Accounting Policies
- -------------------------------
Penelec prepares its 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 Penelec's assets
are subject to their own specific risks and uncertainties and are regularly
reviewed for impairment. Penelec's goodwill will be reviewed for impairment at
least annually in accordance with SFAS 142. Penelec's annual review was
completed in the third quarter of 2002 - the results of that review indicated no
impairment of goodwill. Other assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting these specific factors.
Purchase Accounting - Acquisition of GPU
On November 7, 2001, the merger between FirstEnergy and GPU became
effective, and Penelec became a wholly owned subsidiary of FirstEnergy. The
merger was accounted for by the purchase method of accounting, which 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 were
based primarily on estimates. The adjustments reflected in Penelec's records,
which are subject to adjustment in 2002 when finalized, primarily consist of:
(1) revaluation of certain property, plant and equipment; (2) adjusting
preferred stock subject to mandatory redemption and long-term debt to estimated
fair value; (3) recognizing additional obligations related to retirement
benefits; and (4) recognizing estimated severance and other compensation
liabilities. The excess of the purchase price over the estimated fair values of
the assets acquired and liabilities assumed was recognized as goodwill, which
totaled $873.6 million at September 30, 2002.
Regulatory Accounting
Penelec is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on costs that the regulatory agencies
determine Penelec is 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 Pennsylvania, a significant
amount of regulatory assets have been recorded - $574.3 million as of September
30, 2002. Penelec regularly reviews these assets to assess their ultimate
recoverability within the approved
100
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
In September 2002, Penelec established a $143.9 million reserve, reflecting the
current estimate of the potential adverse impact in a pending Pennsylvania
Supreme Court decision. (See Pennsylvania Regulatory Matters for further
discussion.)
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. Penelec continually monitors its derivative contracts to determine if
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, Penelec enters into commodity
contracts, which increase the impact of derivative accounting judgments.
Revenue Recognition
Penelec follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," Penelec periodically evaluates its 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 impairment must
be recognized in the financial statements. If impairment other than of a
temporary nature has occurred, Penelec recognizes a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and OPEB are dependent upon numerous factors resulting from
actual plan experience and assumptions of future activities.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
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 and the discount rates used in determining the projected benefit
obligation.
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.
101
In selecting an assumed discount rate, FirstEnergy considers fixed
income security yields for AA rated corporate debt. Corporate bond yields, as
well as interest rates in general, have declined in the first nine months of
2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If
the discount rate is reduced from the current assumed rate, pension and OPEB
liabilities and costs would increase in 2003.
FirstEnergy's assumed rate of return on its pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2001, 2000 and 1999, return on plan assets has been (5.5%), (0.3%)
and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed
assuming a 10.25% rate of return on plan assets, consistent with long-term
historical returns produced by the plan's investment portfolio. If a lower rate
of return were to be assumed in 2003, Penelec's reported pension costs would
increase. While OPEB plan assets have also been affected by sharp declines in
the equity market, the impact is moderated due to smaller asset balances.
However, medical cost trends have significantly increased which could affect
future postretirement benefit costs.
As a result of the reduced market value of its pension plan assets
(see Postretirement Plans), FirstEnergy could be required to recognize an
additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers'
Disclosures about Pension and Postretirement Benefits." The offset to the
liability would be recorded as a reduction to common stockholder's equity
through an after-tax charge to other comprehensive income (OCI), and would not
affect net income for 2002. The charge to OCI would reverse in future periods if
the fair value of trust assets exceeds the accumulated benefit obligation. The
amount of pension liability to be recorded as of December 31, 2002, will depend
upon the assumed discount rate (and any other change in FirstEnergy's
assumptions) and actual asset returns experienced in 2002.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
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 as of January 1, 2003. SFAS 143 requires the fair value of a liability
for an asset retirement obligation to 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,
both resulting in a period expense. Upon retirement, a gain or loss would be
recorded if the cost to settle the retirement obligation differs from the
carrying amount.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," issued by the FASB in July 2002, requires the recognition of costs
associated with exit or disposal activities at the time they are incurred rather
than when management commits to a plan of exit or disposal. It also requires the
use of fair value for the measurement of such liabilities. The new standard
supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This
new standard will be 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.
102
Controls and Procedures
- -----------------------
(a) Evaluation of Disclosure Controls and Procedures
The respective registrant's chief executive officer and chief
financial officer have reviewed and evaluated the registrant's disclosure
controls and procedures, as defined in the Securities Exchange Act of 1934 Rules
13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of
this report (Evaluation Date). Based on that evaluation those officers have
concluded that the registrant's disclosure controls and procedures are effective
and were designed to bring to their attention, during the period in which this
quarterly report was being prepared, material information relating to the
registrant and its consolidated subsidiaries by others within those entities.
(b) Changes in Internal Controls
There have been no significant changes in internal controls or in other
factors that could significantly affect those controls subsequent to the
Evaluation Date.
103
PART II. OTHER INFORMATION
- ---------------------------
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits
Exhibit
Number
------
Met-Ed
------
12 Fixed charge ratios
99.1 Certification letter from chief executive officer
99.2 Certification letter from chief financial officer
Penelec
-------
12 Fixed charge ratios
15 Letter from independent public accountants
99.1 Certification letter from chief executive officer
99.2 Certification letter from chief financial officer
JCP&L
-----
12 Fixed charge ratios
15 Letter from independent public accountants
99.2 Certification letter from chief financial officer
99.3 Certification letter from chief executive officer
FirstEnergy, OE and Penn
------------------------
15 Letter from independent public accountants
99.1 Certification letter from chief executive officer
99.2 Certification letter from chief financial officer
CEI and TE
----------
99.1 Certification letter from chief executive officer
99.2 Certification letter from chief financial officer
Pursuant to reporting requirements of respective financings, JCP&L,
Met-Ed and Penelec are required to file fixed charge ratios as an
exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not
have similar financing reporting requirements and have not filed
their respective fixed charge ratios.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K,
neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec
have filed as an exhibit to this Form 10-Q any instrument with
respect to long-term debt if the respective total amount of
securities authorized thereunder does not exceed 10% of their
respective total assets of FirstEnergy and its subsidiaries on a
consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed
or Penelec but hereby agree to furnish to the Commission on request
any such documents.
(b) Reports on Form 8-K
FirstEnergy
-----------
Eight reports on Form 8-K were filed since June 30, 2002. A report
dated August 1, 2002 reported two JCP&L rate filings with the New
Jersey Board of Public Utilities. A report dated August 9, 2002
included conformed copies of Statements Under Oath from H. Peter
Burg, Chief Executive Officer and Richard H. Marsh, Chief Financial
Officer, dated August 8, 2002, as Exhibits. A report dated August 12,
2002 reported updated information following FirstEnergy's August 8,
2002 notification to NRG Energy and its NRG Able Acquisition LLC
affiliate that November 29, 2001 agreements for the NRG purchase of
four power plants from subsidiaries of FirstEnergy had been canceled
because of the affiliate's anticipatory breach of the agreements. A
report dated August 23, 2002 reported updated information provided to
the investment community on activities associated with efforts to
return the Davis-Besse Nuclear Power Station to service in a safe and
reliable manner and other items. A report dated September 11, 2002
reported that research was being conducted on the original reactor
head of Davis-Besse. A report dated September 24, 2002 reported
updated information provided to the investment community on
activities associated with efforts to return Davis-Besse to service;
Met-Ed and Penelec
104
had elected to assign certain provider of last resort
responsibilities to an unregulated supply affiliate through a
wholesale power transaction; and a cost reduction initiative
focused on corporate support services. A report dated October 7,
2002 reported an update of the cost and return to service schedule
estimates for Davis-Besse. A report dated October 31, 2002
reported on plans for instrumentation tubes inspections on the
bottom of the Davis-Besse reactor vessel.
OE and Penn
-----------
OE and Penn each filed one report on Form 8-K since June 30, 2002. A
report dated September 24, 2002 reported a cost reduction initiative
focused on corporate support services.
CEI and TE
----------
CEI and TE each filed six reports on Form 8-K since June 30, 2002. A
report dated August 12, 2002 reported updated information following
FirstEnergy's August 8, 2002 notification to NRG Energy and its NRG
Able Acquisition LLC affiliate that November 29, 2001 agreements for
the NRG purchase of four power plants from subsidiaries of
FirstEnergy had been canceled because of the affiliate's anticipatory
breach of the agreements. A report dated August 23, 2002 reported
updated information provided to the investment community on
activities associated with efforts to return the Davis-Besse Nuclear
Power Station to service in a safe and reliable manner and other
items. A report dated September 11, 2002 reported that research was
being conducted on the original reactor head of Davis-Besse. A report
dated September 24, 2002 reported updated information provided to the
investment community on activities associated with efforts to return
Davis-Besse to service and a cost reduction initiative focused on
corporate support services. A report dated October 7, 2002 reported
an update of the cost and return to service schedule estimates for
Davis-Besse. A report dated October 31, 2002 reported on plans for
instrumentation tubes inspections on the bottom of the Davis-Besse
reactor vessel.
JCP&L
-----
JCP&L filed two reports on Form 8-K since June 30, 2002. A report
dated August 1, 2002 reported two JCP&L rate filings with the New
Jersey Board of Public Utilities. A report dated September 24, 2002
reported a cost reduction initiative focused on corporate support
services.
Met-Ed and Penelec
------------------
Met-Ed and Penelec each filed one report on Form 8-K since June 30,
2002. A report dated September 24, 2002 reported Met-Ed and Penelec
had elected to assign certain provider of last resort
responsibilities to an unregulated supply affiliate through a
wholesale power transaction and a cost reduction initiative focused
on corporate support services.
105
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
each Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
November 13, 2002
FIRSTENERGY CORP.
-----------------
Registrant
OHIO EDISON COMPANY
-------------------
Registrant
THE CLEVELAND ELECTRIC
----------------------
ILLUMINATING COMPANY
--------------------
Registrant
THE TOLEDO EDISON COMPANY
-------------------------
Registrant
PENNSYLVANIA POWER COMPANY
--------------------------
Registrant
JERSEY CENTRAL POWER & LIGHT COMPANY
------------------------------------
Registrant
METROPOLITAN EDISON COMPANY
---------------------------
Registrant
PENNSYLVANIA ELECTRIC COMPANY
-----------------------------
Registrant
/s/ Harvey L. Wagner
---------------------------------
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
106
Certification
I, H. Peter Burg, certify that:
1. I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp.,
Ohio Edison Company, The Cleveland Electric Illuminating Company, The
Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison
Company and Pennsylvania Electric Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 13, 2002
----------------------------
Chief Executive Officer
107
Certification
I, Earl T. Carey, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Jersey Central Power
& Light Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 13, 2002
----------------------------
Chief Executive Officer
108
Certification
I, Richard H. Marsh, certify that:
1. I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp.,
Ohio Edison Company, The Cleveland Electric Illuminating Company, The
Toledo Edison Company, Pennsylvania Power Company, Jersey Central Power &
Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 13, 2002
----------------------------
Chief Financial Officer
109