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 March 31, 2003
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 by check mark whether each registrant is an accelerated
filer ( as defined in Rule 12b-2 of the Act):
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 MAY 9, 2003
----- -----------------
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.................................. 1-13
FirstEnergy Corp.
Consolidated Statements of Income.............................. 14
Consolidated Balance Sheets.................................... 15-16
Consolidated Statements of Cash Flows.......................... 17
Report of Independent Accountants.............................. 18
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 19-38
Ohio Edison Company
Consolidated Statements of Income.............................. 39
Consolidated Balance Sheets.................................... 40-41
Consolidated Statements of Cash Flows.......................... 42
Report of Independent Accountants.............................. 43
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 44-51
The Cleveland Electric Illuminating Company
Consolidated Statements of Income.............................. 52
Consolidated Balance Sheets.................................... 53-54
Consolidated Statements of Cash Flows.......................... 55
Report of Independent Accountants.............................. 56
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 57-64
The Toledo Edison Company
Consolidated Statements of Income.............................. 65
Consolidated Balance Sheets.................................... 66-67
Consolidated Statements of Cash Flows.......................... 68
Report of Independent Accountants.............................. 69
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 70-77
Pennsylvania Power Company
Statements of Income........................................... 78
Balance Sheets................................................. 79-80
Statements of Cash Flows....................................... 81
Report of Independent Accountants.............................. 82
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 83-88
Jersey Central Power & Light Company
Consolidated Statements of Income.............................. 89
Consolidated Balance Sheets.................................... 90-91
Consolidated Statements of Cash Flows.......................... 92
Report of Independent Accountants.............................. 93
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 94-101
TABLE OF CONTENTS (Cont'd)
Pages
Metropolitan Edison Company
Consolidated Statements of Income.............................. 102
Consolidated Balance Sheets.................................... 103-104
Consolidated Statements of Cash Flows.......................... 105
Report of Independent Accountants.............................. 106
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 107-114
Pennsylvania Electric Company
Consolidated Statements of Income.............................. 115
Consolidated Balance Sheets.................................... 116-117
Consolidated Statements of Cash Flows.......................... 118
Report of Independent Accountants.............................. 119
Management's Discussion and Analysis of Results
of Operations and Financial Condition........................ 120-127
Controls and Procedures............................................. 128
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. JCP&L, Met-Ed and Penelec were acquired in a merger (which was
effective November 7, 2001) 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. FirstEnergy's consolidated
financial statements also include its other principal subsidiaries: FirstEnergy
Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); 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. FSG is the parent company of several
heating, ventilating, air conditioning and energy management companies, and MYR
is a utility infrastructure construction service company. MARBEL is a fully
integrated natural gas company. GPU Capital owns and operates electric
distribution systems in foreign countries (see Note 3) and GPU Power owns and
operates generation facilities in foreign countries. FECO and GPUS provide
legal, financial and other corporate support services to affiliated FirstEnergy
companies. Significant intercompany transactions have been eliminated.
The Companies follow the accounting policies and practices prescribed
by the Securities and Exchange Commission (SEC), the Public Utilities Commission
of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New
Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory
Commission (FERC). The 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 and Amendment No. 1 on Form 10-K/A for the year ended December 31, 2002 for
FirstEnergy and the Companies. 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, as discussed further
in Note 5.
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 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 the 7.35% and 7.34% subordinated
debentures (aggregate principal amount of $103.1 million each)
1
of Met-Ed and Penelec, respectively. In each case, the applicable parent company
has effectively provided a full and unconditional guarantee of the trust's
obligations under the preferred securities.
Securitized Transition Bonds
In June 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned
limited liability company of JCP&L, sold $320 million of transition bonds to
securitize the recovery of JCP&L's bondable stranded costs associated with the
previously divested Oyster Creek Nuclear Generating Station.
JCP&L does not own 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 represents the irrevocable right of a
utility company to charge, collect and receive from its customers, through a
non-bypassable transition bond charge, the principal amount and interest on the
transition bonds and other fees and expenses associated with their issuance.
JCP&L, as servicer, manages and administers the bondable transition property,
including the billing, collection and remittance of the transition bond charge,
pursuant to a servicing agreement with the Issuer. JCP&L is entitled to a
quarterly servicing fee of $100,000 that is payable from transition bond charge
collections.
Derivative Accounting
FirstEnergy is exposed to financial risks resulting from the
fluctuation of interest rates and commodity prices, including electricity,
natural gas and coal. To manage the volatility relating to these exposures,
FirstEnergy uses a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes, and to a lesser extent,
for trading purposes. FirstEnergy's Risk Policy Committee, comprised of
executive officers, exercises an independent risk oversight function to ensure
compliance with corporate risk management policies and prudent risk management
practices.
FirstEnergy uses derivatives to hedge the risk of price and interest
rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash
flow hedges of electricity and natural gas purchases. The maximum periods over
which the variability of electricity and natural gas cash flows are hedged are
two and three years, respectively. Gains and losses from hedges of commodity
price risks are included in net income when the underlying hedged commodities
are delivered. Also, gains and losses are included in net income when
ineffectiveness occurs on certain natural gas hedges. FirstEnergy entered into
interest rate derivative transactions during 2001 to hedge a portion of the
anticipated interest payments on debt related to the GPU acquisition. Gains and
losses from hedges of anticipated interest payments on acquisition debt will be
included in net income over the periods that hedged interest payments are made -
5, 10 and 30 years. Gains and losses from derivative contracts are included in
other operating expenses. The current net deferred loss of $105.8 million
included in Accumulated Other Comprehensive Loss (AOCL) as of March 31, 2003,
for derivative hedging activity, as compared to the December 31, 2002 balance of
$110.2 million in net deferred losses, resulted from a $8.8 million reduction
related to current hedging activity and a $4.4 million increase due to net hedge
gains included in earnings during the three months ended March 31, 2003.
Approximately $20.2 million (after tax) of the current net deferred loss on
derivative instruments in AOCL is expected to be reclassified to earnings during
the next twelve months as hedged transactions occur. However, the fair value of
these derivative instruments will fluctuate from period to period based on
various market factors and will generally be more than offset by the margin on
related sales and revenues. FirstEnergy also entered into fixed-to-floating
interest rate swap agreements during 2002 to increase the variable-rate
component of its debt portfolio. These derivatives are treated as fair value
hedges of fixed-rate, long-term debt issues-protecting against the risk of
changes in the fair value of fixed-rate debt instruments due to lower interest
rates. Swap maturities, call options and interest payment dates match those of
the underlying obligations resulting in no ineffectiveness in these hedge
positions. The swap agreements consummated in the first quarter of 2003 are
based on a notional principal amount of $200 million. As of March 31, 2003, the
notional amount of FirstEnergy's fixed-for-floating rate interest rate swaps
totaled $700 million.
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
March 31, 2003, FirstEnergy's AOCL was approximately $657.4 million as compared
to the December 31, 2002 balance of $663.2 million. Comprehensive income for the
first quarter of 2003 and 2002 are shown in the following table:
2
Three months ended March 31,
----------------------------
2003 2002
---- ----
(In thousands)
Net income................................. $240,985 $116,493
Other comprehensive income, net of tax:
Derivative hedge transactions............ 4,341 35,844
All other................................ 1,484 730
-------- --------
Comprehensive income....................... $246,810 $153,067
======== ========
Stock-Based Compensation
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board (APB) Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans. No material stock-based employee compensation
expense is reflected in net income as all options granted under those plans have
exercise prices equal to the market value of the underlying common stock on the
respective grant dates, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the
fair value method, a higher value would have been assigned to the options
granted. The effects of applying fair value accounting to FirstEnergy's stock
options would be to reduce net income and earnings per share. The following
table summarizes this effect.
Three Months Ended
March 31,
------------------
2003 2002
(In thousands)
Net Income, as reported............. $240,985 $116,493
Add back compensation expense
reported in net income, net of tax
(based on APB 25)................. 43 43
Deduct compensation expense based
upon fair value, net of tax....... (2,983) (1,402)
- --------------------------------------------------------------
Adjusted net income................. $238,045 $115,134
-------------------------------------------------------------
Earnings Per Share of Common Stock -
Basic
As Reported..................... $0.82 $0.40
Adjusted........................ $0.81 $0.39
Diluted
As Reported..................... $0.82 $0.40
Adjusted........................ $0.81 $0.39
Change in Previously Reported Income Statement Classification -
FirstEnergy recorded an increase to income during the three months
ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million)
relative to a decision to retain an interest in the Avon Energy Partners
Holdings (Avon) business previously classified as held for sale - see Note 3.
This amount represents the aggregate results of operations of Avon for the
period this business was held for sale. It was previously reported on the
Consolidated Statement of Income as the cumulative effect of a change in
accounting. In April 2003, it was determined that this amount should instead
have been classified in operations. As further discussed in Note 3, the decision
to retain Avon was made in the first quarter of 2002 and Avon's results of
operations for that quarter have been classified in their respective revenue and
expense captions on the Consolidated Statement of Income. This change in
classification had no effect on previously reported net income. The effects of
this change on the Consolidated Statement of Income previously reported for the
three months ended March 31, 2002 are as follows:
3
Three Months Ended March 31, 2002
---------------------------------
As Previously Revised
Presented Presentation
- --------------------------------------------------------------------------------------------------------------------
Revenues (Note 5)............................................................... $2,802,157 $2,853,278
Expenses (Note 5).............................................................. 2,376,713 2,363,634
---------- ----------
Income before interest and income taxes......................................... 425,444 489,644
Net interest charges............................................................ 259,822 278,722
Income taxes.................................................................... 80,829 94,429
---------- ----------
Income before cumulative effect of accounting change............................ 84,793 116,493
Cumulative effect of accounting change.......................................... 31,700 --
---------- ----------
Net income...................................................................... $ 116,493 $ 116,493
========== ==========
Basic Earnings Per Share:
Income before cumulative effect of accounting change......................... $0.29 $0.40
Cumulative effect of accounting change....................................... 0.11 --
----- -----
Net income................................................................... $0.40 $0.40
===== =====
Diluted Earnings Per Share:
Income before cumulative effect of accounting change......................... $0.29 $0.40
Cumulative effect of accounting change....................................... 0.11 --
----- -----
Net income................................................................... $0.40 $0.40
===== =====
2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:
Capital Expenditures
FirstEnergy's current forecast reflects expenditures of approximately
$3.1 billion (OE-$268 million, CEI-$312 million, TE-$169 million, Penn-$123
million, JCP&L-$462 million, Met-Ed-$288 million, Penelec-$328 million,
ATSI-$131 million, FES-$823 million and other subsidiaries-$147 million) for
property additions and improvements from 2003-2007, of which approximately $727
million (OE-$86 million, CEI-$96 million, TE-$54 million, Penn-$53 million,
JCP&L-$102 million, Met-Ed-$53 million, Penelec-$54 million, ATSI-$25 million,
FES-$124 million and other subsidiaries-$80 million) is applicable to 2003.
Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $485 million (OE-$55 million, CEI-$53 million,
TE-$34 million, Penn-$42 million and FES-$301 million), of which approximately
$69 million (OE-$23 million, CEI-$15 million, TE-$12 million and Penn-$19
million) applies to 2003.
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 March 31, 2003, outstanding guarantees and other assurances aggregated $960.2
million.
FirstEnergy guarantees energy and energy-related payments of its
subsidiaries involved in energy marketing activities - principally to facilitate
normal physical transactions involving electricity, gas, emission allowances and
coal. FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy and its subsidiaries to fulfill
the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financing where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables
the counterparty's legal claim to be satisfied by other FirstEnergy assets. The
likelihood that such parental guarantees of $872.7 million as of March 31, 2003
will increase amounts otherwise to be paid by FirstEnergy to meet its
obligations incurred in connection with financings and 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. 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 March 31, 2003, rating-contingent
collateralization totaled $61.7 million. FirstEnergy monitors these
collateralization provisions and updates its total exposure monthly.
4
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $159 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2003 through 2007.
The Companies are required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies believe they are in compliance with the current SO2 and
nitrogen 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 Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit found constitutional and other defects in
the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new
NAAQS rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and will
depend if and how they are ultimately implemented by the states in which the
Companies operate affected facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of Ohio
for which hearings began 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 March 31, 2003, 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
5
societal benefits charge. The Companies have total accrued liabilities
aggregating approximately $53.9 million (JCP&L-$47.1 million, CEI-$2.5 million,
TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.3 million and other-$3.6
million) as of March 31, 2003.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on FirstEnergy's
earnings and competitive position. These environmental regulations affect
FirstEnergy's earnings and competitive position to the extent it competes with
companies that are not subject to such regulations and therefore do not bear the
risk of costs associated with compliance, or failure to comply, with such
regulations. FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict whether environmental regulations will
change and what, if any, the effects of such change would be.
Other Commitments and Contingencies
GPU made significant investments in foreign businesses and facilities
through its GPU Capital and GPU Power subsidiaries. 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 through September 30, 2003, under certain circumstances, to make
additional standby equity contributions to TEBSA of $21.3 million, which
FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA
project is $239 million as of March 31, 2003. 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. FirstEnergy provided the
TEBSA project lenders a $50 million letter of credit (LOC) issued by Bank One
under FirstEnergy's existing $250 million LOC capacity available as part of the
$1.5 billion FirstEnergy credit facility to obtain TEBSA lender consent to
abandon its Argentina operations, GPU Empresa Distribuidora Electrica Regional
S.A. and affiliates (Emdersa) (see Note 3 below).
3 - DIVESTITURES:
INTERNATIONAL OPERATIONS-
FirstEnergy had identified certain former GPU international
operations for divestiture within one year of the merger. These operations
constitute individual "lines of business" as defined in APB 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 2001 Consolidated Statement of Income. Additionally,
assets and liabilities of these international operations had been segregated
under separate captions on the Consolidated Balance Sheet as of December 31,
2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale."
Upon completion of its merger with GPU, FirstEnergy accepted an
October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase
Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc,
for $2.1 billion (including the assumption of $1.7 billion of debt). The
transaction closed on May 8, 2002 and reflected the March 2002 modification of
Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest
in Avon for approximately $1.9 billion (including the assumption of $1.7 billion
of debt). Proceeds to FirstEnergy included $155 million in cash and a note
receivable for approximately $87 million (representing the present value of $19
million per year to be received over six years beginning in 2003) from Aquila
for its 79.9 percent interest. FirstEnergy and Aquila together own all of the
outstanding shares of Avon through a jointly owned subsidiary, with each company
having an ownership voting interest. Originally, in accordance with applicable
accounting guidance, the earnings of those foreign operations were not
recognized in current earnings from the date of the GPU acquisition. However, as
a result of the decision to retain an ownership interest in Avon in the quarter
ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not
Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold"
required FirstEnergy to reallocate the purchase price of GPU based on amounts as
of the purchase date as if Avon had never been held for sale, including reversal
of the effects of having applied EITF Issue No. 87-11, to the transaction. The
effect of reallocating the purchase price and reversal of the effects of EITF
Issue No. 87-11, including the allocation of capitalized interest, has been
reflected in the Consolidated Statement of Income for the quarter ended March
31, 2002 by reclassifying certain revenue and expense amounts related to
activity during the quarter ended March 31, 2002 to their respective income
statement classifications. See Note 1 for the effects of the change in
classification. In the fourth quarter of 2002,
6
FirstEnergy recorded a $50 million charge ($32.5 million net of tax) to reduce
the carrying value of its remaining 20.1 percent interest.
GPU's former Argentina operations were also identified by FirstEnergy
for divestiture within one year of the merger. FirstEnergy determined the fair
value of 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 included currency devaluation, restrictions
on repatriation of cash, and the anticipation of future asset sales in that
region by competitors. FirstEnergy did not reach a definitive agreement to sell
Emdersa as of December 31, 2002. Therefore, these assets were no longer
classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of
December 31, 2002. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded
in the fourth quarter of 2002 a one-time, non-cash charge included as a
"Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its
2002 Consolidated Statement of Income related to Emdersa's cumulative results of
operations from November 7, 2001 through September 30, 2002. The amount of this
one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock
(comprised of $108.9 million in currency transaction losses arising principally
from U.S. dollar denominated debt, offset by $15.2 million of operating income).
In October 2002, FirstEnergy began consolidating the results of
Emdersa's operations in its financial statements. In addition to the currency
transaction losses of $108.9 million, FirstEnergy also recognized a currency
translation adjustment (CTA) in other comprehensive income (OCI) of $91.5
million as of December 31, 2002, which reduced FirstEnergy's common
stockholders' equity. This adjustment represents the impact of translating
Emdersa's financial statements from its functional currency to the U.S. dollar
for GAAP financial reporting.
On April 18, 2003, FirstEnergy divested its ownership in Emdersa
through the abandonment of its shares in Emdersa's parent company, GPU Argentina
Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's
shares to the independent Board of Directors of GPU Argentina Holdings,
relieving FirstEnergy of all rights and obligations relative to this business.
As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash
charge of $63 million, or $0.21 per share of common stock in the second quarter
of 2003. This charge is the result of realizing the CTA losses through its
current period earnings ($90 million, or $0.30 per share), partially offset by
the gain recognized from eliminating its investment in Emdersa ($27 million, or
$0.09 per share). Since FirstEnergy had previously recorded $90 million of CTA
adjustments in OCI, the net effect of the $63 million charge will be an increase
in common stockholders' equity of $27 million.
The $63 million charge does not include the anticipated income tax
benefits related to the abandonment. These tax benefits will be fully reserved
during the second quarter. FirstEnergy anticipates tax benefits of approximately
$129 million, of which $50 million would increase net income in the period that
it becomes probable those benefits will be realized. The remaining $79 million
of tax benefits would reduce goodwill recognized in connection with the
acquisition of GPU.
SALE OF GENERATING ASSETS-
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On
August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement
because NRG stated that it could not complete the transaction under the original
terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves
the right to pursue legal action against NRG, its affiliate and its parent, Xcel
Energy for damages, based on the anticipatory breach of the agreement. On
February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's
request for arbitration against NRG.
In December 2002, FirstEnergy decided to retain ownership of these
plants after reviewing other bids it subsequently received from other parties
who had expressed interest in purchasing the plants. Since FirstEnergy did not
execute a sales agreement by year-end, it reflected approximately $74 million
($43 million net of tax) of previously unrecognized depreciation and other
transaction costs in the fourth quarter of 2002 related to these plants from
November 2001 through December 2002 on its Consolidated Statement of Income.
4 - REGULATORY MATTERS:
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in the
Companies' respective state regulatory plans:
o allowing the Companies' electric customers to select their
generation suppliers;
o establishing provider of last resort (PLR) obligations to
customers in the Companies' service areas;
o allowing recovery of potentially stranded investment (sometimes
referred to as transition costs);
7
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
In July 1999, Ohio's electric utility restructuring legislation,
which allowed Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the
legislation provided for a 5% reduction on the generation portion of residential
customers' bills and the opportunity to recover transition costs, including
regulatory assets, from January 1, 2001 through December 31, 2005 (market
development period). The period for the recovery of regulatory assets only can
be extended up to December 31, 2010. The PUCO was authorized to determine the
level of transition cost recovery, as well as the recovery period for the
regulatory assets portion of those costs, in considering each Ohio electric
utility's transition plan application.
In July 2000, the PUCO approved FirstEnergy's transition plan for OE,
CEI and TE (Ohio Companies) as modified by a settlement agreement with major
parties to the transition plan. The application of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation" to OE's generation business and the nonnuclear generation
businesses of CEI and TE was discontinued with the issuance of the PUCO
transition plan order, as described further below. Major provisions of the
settlement agreement consisted of approval of recovery of generation-related
transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6
billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to
regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0
billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later
than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period
of recovery is provided for in the settlement agreement. The generation-related
transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0
billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets
recognized as regulatory assets as described further below, $2.4 billion, net of
deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion)
of above market operating lease costs and $0.8 billion, net of deferred income
taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that
were reflected on CEI's and TE's regulatory financial statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 1,120 MW of generation capacity through 2005 at established
prices for sales to the Ohio Companies' retail customers. Customer prices are
frozen through the five-year market development period, which runs through the
end of 2005, except for certain limited statutory exceptions, including the 5%
reduction referred to above. In February 2003, the Ohio Companies were
authorized increases in annual revenues aggregating approximately $50 million
(OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax
costs resulting from the Ohio deregulation legislation.
FirstEnergy's Ohio customers choosing alternative suppliers receive
an additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
respective transition cost recovery period. If the customer shopping goals
established in the agreement had not been achieved by the end of 2005, the
transition cost recovery periods could have been shortened for OE, CEI and TE to
reduce recovery by as much as $500 million (OE - $250 million, CEI - $170
million and TE - $80 million). The Ohio Companies achieved all of their required
20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that
there will be no regulatory action reducing the recoverable transition costs.
New Jersey
JCP&L's 2001 Final Decision and Order (Final Order) with respect to
its rate unbundling, stranded cost and restructuring filings confirmed rate
reductions set forth in its 1999 Summary Order, which remain in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable societal benefits charge (SBC) to recover
costs which include nuclear plant decommissioning and manufactured gas plant
remediation, as well as a non-bypassable market transition charge (MTC)
primarily to recover stranded costs. The NJBPU has deferred making a final
determination of the net proceeds and stranded costs related to prior generating
asset divestitures until JCP&L's request for an Internal Revenue Service (IRS)
ruling regarding the treatment of associated federal income tax benefits is
acted upon. Should the IRS ruling support the return of the tax benefits to
customers, there would be no effect to FirstEnergy's or JCP&L's net income since
the contingency existed prior to the merger.
8
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. In 2002, JCP&L received NJBPU authorization to issue $320 million of
transition bonds to securitize the recovery of these costs and which 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 the transition
bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June
2002 - those bonds are 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 March 31, 2003, the
accumulated deferred cost balance totaled approximately $530 million. The NJBPU
also allowed securitization of JCP&L's deferred balance to the extent permitted
by law upon application by JCP&L and a determination by the NJBPU that the
conditions of the New Jersey restructuring legislation are met. There can be no
assurance as to the extent, if any, that the NJBPU will permit such
securitization.
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L submitted two rate
filings with the NJBPU in August 2002. The first filing requested increases in
base electric rates of approximately $98 million annually. The second filing was
a request to recover deferred costs that exceeded amounts being recovered under
the current MTC and SBC rates; one proposed method of recovery of these costs is
the securitization of the deferred balance. This securitization methodology is
similar to the Oyster Creek securitization discussed above. Hearings began in
February 2003. On March 18, 2003, a report prepared by independent auditors
addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002,
was transmitted to the Office of Administrative Law, where JCP&L's rate case is
being heard. While the auditors concluded that JCP&L's energy procurement
strategy and process was reasonable and prudent, they identified potential
disallowances approximating $17 million. The report subjected $436 million of
deferred costs to a retrospective prudence review during a period of extreme
price uncertainty and volatility in the energy markets. Although JCP&L disagrees
with the potential disallowances, it is pleased with the report's major
conclusions and overall tone. Hearings concluded on April 28, 2003, and initial
briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings
requesting an aggregate rate increase of approximately $122 million in base
electric rates and the recovery of deferred costs based on the securitization
methodology discussed above. If the securitization methodology is not allowed,
then JCP&L has requested deferred cost recovery over a four-year period with a
return on the unamortized deferred cost balance. This alternative would increase
the overall rate request to approximately $246 million. JCP&L strongly disagrees
with many of the positions taken by NJBPU Staff. The Staff's position would
result in a $119 million estimated annual earnings decrease related to the
electricity delivery charge. In addition, the Staff recommended disallowing
approximately $153 million of deferred energy costs which would result in a
one-time pre-tax charge against earnings of $153 million (or $0.31 per share of
common stock). JCP&L will respond to the Staff's position in its Reply Brief
which is due on May 21, 2003. The Administrative Law Judge's recommended
decision is due by the end of June 2003 and the NJBPU's subsequent decision is
due in July 2003.
In 1997, the NJBPU authorized JCP&L to recover from customers,
subject to possible refund, $135 million of costs incurred in connection with a
1996 buyout of a power purchase agreement. JCP&L has recovered the full $135
million; the NJBPU has established a procedural schedule to take further
evidence with respect to the buyout to enable it to make a final prudence
determination contemporaneously with the resolution of the pending rate case.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The auction
results were approved by the NJBPU in February 2002, removing JCP&L's BGS
obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In
February 2003, the NJBPU approved the BGS auction results for the period
beginning August 1, 2003. The auction covered a fixed price bid (applicable to
all residential and smaller commercial and industrial customers) and an hourly
price bid (applicable to all large industrial customers) process. JCP&L sells
all self-supplied energy (NUGs and owned generation) to the wholesale market
with offsetting credits to its deferred energy balances.
Pennsylvania
The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed
and Penelec. In 2000, the PPUC disallowed a portion of the requested additional
stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate
restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS
ruling regarding the return of certain unamortized investment tax credits and
excess deferred income tax benefits to customers. Similar to JCP&L's situation,
if the IRS ruling ultimately supports returning these tax benefits to customers,
there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income
since the contingency existed prior to the merger.
9
As a result of their generating asset divestitures, Met-Ed and
Penelec obtained their supply of electricity to meet their PLR obligations
almost entirely from contracted and open market purchases. In 2000, Met-Ed and
Penelec filed a petition with the PPUC seeking permission to defer, for future
recovery, energy costs in excess of amounts reflected in their capped generation
rates; the PPUC subsequently consolidated this petition in January 2001 with the
FirstEnergy/GPU merger proceeding.
In June 2001, the PPUC entered orders approving the Settlement
Stipulation with all of the major parties in the combined merger and rate relief
proceedings which approved the merger and provided Met-Ed and Penelec PLR
deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and
Penelec to defer for future recovery the difference between their actual energy
costs and those reflected in their capped generation rates, retroactive to
January 1, 2001. Correspondingly, in the event that energy costs incurred by
Met-Ed and Penelec would be below their respective capped generation rates, that
difference would have reduced costs that had been deferred for recovery in
future periods. This PLR deferral accounting procedure was denied in a court
decision discussed below. Met-Ed's and Penelec's PLR obligations extend through
December 31, 2010; during that period competitive transition charge (CTC)
revenues would have been applied to their stranded costs. Met-Ed and Penelec
would have been permitted to recover any remaining stranded costs through a
continuation of the CTC after December 31, 2010 through no later than December
31, 2015. Any amounts not expected to be recovered by December 31, 2015 would
have been written off at the time such nonrecovery became probable.
Several parties had filed Petitions for Review in June and July 2001
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders.
On February 21, 2002, the Court affirmed the PPUC decision regarding the
FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to
the issue of merger savings. The Court reversed the PPUC's decision regarding
the PLR obligations of Met-Ed and Penelec, and rejected those parts of the
settlement that permitted the companies to defer for accounting purposes the
difference between their wholesale power costs and the amount that they collect
from retail customers. FirstEnergy and the PPUC each filed a Petition for
Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002,
asking it to review the Commonwealth Court decision. Also on March 25, 2002,
Citizens Power filed a motion seeking an appeal of the Commonwealth Court's
decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme
Court. In September 2002, FirstEnergy established reserves for Met-Ed's and
Penelec's PLR deferred energy costs which aggregated $287.1 million. The
reserves reflected the potential adverse impact of a pending Pennsylvania
Supreme Court decision whether to review the Commonwealth Court ruling.
FirstEnergy recorded an aggregate non-cash charge to income of $55.8 million
($32.6 million net of tax), or $0.11 per share of common stock, for the deferred
costs incurred subsequent to the merger. The reserve for the remaining $231.3
million of deferred costs increased goodwill by an aggregate net of tax amount
of $135.3 million.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which
effectively affirmed the PPUC's order approving the merger between FirstEnergy
and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed
and Penelec and remanded the merger savings issue back to the PPUC. On April 2,
2003, the PPUC remanded the merger savings issue to the Office of Administrative
Law for hearings and directed Met-Ed and Penelec to file a position paper on the
effect of the Commonwealth Court's order on the Settlement Stipulation by May 2,
2003. Because FirstEnergy had already reserved for the deferred energy costs and
FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed
and Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and
Penelec believe that the disallowance of continued CTC recovery of PLR costs
will not have a future adverse financial impact during that period.
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to their FES affiliate through a wholesale power sale agreement.
The PLR sale currently runs through December 2003 and will be automatically
extended for each successive calendar year unless any party elects to cancel the
agreement by November 1 of the preceding year. Under the terms of the wholesale
agreement, FES assumed the supply obligation and the supply profit and loss
risk, for the portion of power supply requirements not self-supplied by Met-Ed
and Penelec under their NUG contracts and other existing power contracts with
nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and
Penelec's exposure to high wholesale power prices by providing power at or below
the shopping credit for their uncommitted PLR energy costs during the term of
the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled
PLR on-peak obligation through 2004 and a portion of 2005, the period during
which deferred accounting was previously allowed under the PPUC's order. Met-Ed
and Penelec are authorized to continue deferring differences between NUG
contract costs and amounts recovered through their capped generation rates.
5 - NEW ACCOUNTING STANDARDS:
In June 2001, the Financial Accounting Standards Board (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
(ARO) 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
10
depreciated and the present value of the asset retirement liability increases,
resulting in a period expense. However, rate-regulated entities may recognize a
regulatory asset or liability instead, if the criteria for such treatment are
met. Upon retirement, a gain or loss would be recorded if the cost to settle the
retirement obligation differs from the carrying amount.
FirstEnergy identified applicable legal obligations as defined under
the new standard for nuclear power plant decommissioning, reclamation of a
sludge disposal pond related to the Bruce Mansfield plant, and closure of two
coal ash disposal sites. As a result of adopting SFAS 143 in January 2003 asset
retirement costs were recorded in the amount of $602 million as part of the
carrying amount of the related long-lived asset, offset by accumulated
depreciation of $415 million. The ARO liability at the date of adoption was
$1.109 billion, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. At December 31, 2002,
FirstEnergy had recorded decommissioning liabilities of $1.232 billion,
including unrealized gains on the decommissioning trust funds of $12 million.
FirstEnergy expects substantially all nuclear decommissioning costs for Met-Ed,
Penelec, JCP&L and Penn would be recoverable in rates over time. Therefore,
FirstEnergy recognized a regulatory liability of $185 million upon adoption of
SFAS 143 for the transition amounts related to establishing the ARO for nuclear
decommissioning for these operating companies. The remaining cumulative effect
adjustment for unrecognized depreciation and accretion offset by the reduction
in the existing decommissioning liabilities and ceasing the accounting practice
of depreciating non-regulated generation assets using a cost of removal
component was a $174.7 million increase to income, or a $102.1 million increase
net of tax, or $0.35 per share of common stock (basic and diluted). The $12
million of unrealized gains, $7 million net of tax, included in the
decommissioning liability balances at December 31, 2002 was offset against OCI
upon adoption of SFAS 143.
FirstEnergy recorded an ARO for nuclear decommissioning ($1.096
billion) of the Beaver Valley 1, Beaver Valley 2, Davis-Besse, Perry, and TMI-2
nuclear generation facilities with the remaining ARO related to Bruce
Mansfield's sludge impoundment facilities and two coal ash disposal sites. The
Company maintains nuclear decommissioning trust funds, which had balances at
March 31, 2003 of $1.061 billion. This number represents the fair value of the
assets that are legally restricted for purposes of settling the nuclear
decommissioning ARO. The following table provides the beginning and ending
aggregate carrying amount of the ARO and the changes to the balance for the
period of January 1, 2003 through March 31, 2003.
ARO Reconciliation
---------------------------------------------------------------------
(millions)
Beginning balance as of January 1, 2003 ................. $1,109
Liabilities incurred in the current period............. --
Liabilities settled in the current period.............. --
Accretion expense...................................... 18
Revisions in estimated cash flows........................ --
--------------------------------------------------------------------
Ending balance as of March 31, 2003...................... $1,127
--------------------------------------------------------------------
The following table provides on an adjusted basis the year-end
balance of the ARO related to nuclear decommissioning and sludge impoundment for
2002, as if SFAS 143 had been adopted on January 1, 2002.
Adjusted ARO Reconciliation
---------------------------------------------------------------------
(millions)
Beginning balance as of January 1, 2002.................. $1,042
Accretion 2002........................................... 67
--------------------------------------------------------------------
Ending balance as of December 31, 2002 ................. $1,109
--------------------------------------------------------------------
In accordance with SFAS 143 FirstEnergy ceased the accounting
practice of depreciating non-regulated generation assets using a cost of removal
component in the depreciation rates that are applied to the generation assets.
This practice recognizes accumulated depreciation in excess of the historical
cost of an asset, because the removal cost exceeds the estimated salvage value.
The change in accounting resulted in a $60 million credit to income as part of
the SFAS 143 cumulative effect adjustment. Beginning in 2003 depreciation rates
applied to non-regulated generation assets will exclude the cost of removal
component and cost of removal will be charged to income rather than charged to
the accumulated provision for depreciation. In accordance with SFAS 71, the
regulated plant assets will continue the accounting practice of depreciating
assets using a cost of removal component in the depreciation rates. The net
removal cost credit balance included in the accumulated provision for regulated
assets at March 31, 2003 is $296.1 million.
The following table provides on an adjusted basis the effect on
income, as if the accounting for SFAS 143 had been applied in the first quarter
2002.
11
Effect of the Change in Accounting Principle
Applied Retroactively to the First Quarter of 2002
----------------------------------------------------
Increase(Decrease)
(millions)
Reported net income...................... $116
-------------------------------------------------
Replacement of decommissioning expense... 26
Depreciation of asset retirement cost.... (2)
Accretion of asset retirement cost....... (10)
Income tax effect........................ (6)
--------------------------------------------------
Total earnings effect.................... 8
-------------------------------------------------
Net income adjusted...................... $124
=================================================
Earnings per share of common stock
(basic and diluted):
Net income as previously reported $0.40
Adjustment for effect of change in
accounting principle applied
retroactively 0.02
-----
Net income adjusted $0.42
=====
In January 2003, the FASB issued an interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (FirstEnergy's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements, the sale of preferred securities and debt
secured by bondable property, which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46.
FirstEnergy currently consolidates the majority of these entities and
believes it will continue to consolidate following the adoption of FIN 46. In
addition to the entities FirstEnergy is currently consolidating FirstEnergy
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $12.0 million.
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS133 for decisions made by the Derivative Implementation Group, as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for quarters
which began prior to June 15, 2003, which continue to be applied based on their
original effective dates. FirstEnergy is currently assessing the new standard
and has not yet determined the impact on its financial statements.
In June 2002, the EITF reached a partial consensus on Issue No.
02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities." Based on the EITF's partial consensus position, for periods after
July 15, 2002, mark-to-market revenues and expenses and their related
kilowatt-hour (KWH) sales and purchases on energy trading contracts must be
shown on a net basis in the Consolidated Statements of Income. Prior to its
adoption for 2002 year end reporting, FirstEnergy had previously reported such
contracts as gross revenues and purchased power costs. Comparative quarterly
disclosures and the Consolidated Statements of Income for revenues and expenses
have been reclassified for 2002 to conform with the revised presentation. In
addition, the related KWH sales and purchases statistics described under
Management's Discussion and Analysis of Results of Operations and Financial
Condition were reclassified. The following table displays the impact of changing
to a net presentation for FirstEnergy's energy trading operations.
12
Three Months Ended
March 31, 2002
---------------------
2002 Impact of Recording Energy Trading Net Revenues Expenses
------------------------------------------------------------------------
Revised Revised
------------------------------------------------------------------------
(in millions)
Total before adjustment........................ $2,893 $2,404
Adjustment..................................... (40) (40)
-------------------------------------------------------------------------
Total as reported.............................. $2,853 $2,364
=========================================================================
6 - SEGMENT INFORMATION:
FirstEnergy operates under two reportable segments: regulated
services and competitive services. The aggregate "Other" segments do not
individually meet the criteria to be considered a reportable segment. "Other"
consists of interest expense related to the 2001 merger acquisition debt; the
corporate support services operating segment and the international businesses
acquired in the 2001 merger. The international business assets reflected in the
2002 "Other" assets amount included assets in the United Kingdom identified for
divestiture (see Note 3 - Divestitures) which were sold in the second quarter of
2002. As those assets were in the process of being sold, their performance was
not being reviewed by a chief operating decision maker and in accordance with
SFAS 131, "Disclosures about Segments of an Enterprise and Related Information,"
did not qualify as an operating segment. The remaining assets and revenues for
the corporate support services and the remaining international businesses were
below the quantifiable threshold for operating segments for separate disclosure
as "reportable segments." FirstEnergy's primary segment is its regulated
services segment, which includes eight electric utility operating companies in
Ohio, Pennsylvania and New Jersey that provide electric transmission and
distribution services. Its other material business segment consists of the
subsidiaries that operate unregulated energy and energy-related businesses.
The regulated services segment designs, constructs, operates and
maintains FirstEnergy's regulated transmission and distribution systems. It also
provides generation services to regulated franchise customers who have not
chosen 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.
Segment Financial Information
-----------------------------
Regulated Competitive Reconciling
Services Services Other(c) Adjustments Consolidated(c)
--------- ----------- -------- ----------- ---------------
(In millions)
Three Months Ended:
- -------------------
March 31, 2003
--------------
External revenues..................... $ 2,315 $ 866 $ 51 $ 12 (a) $ 3,244
Internal revenues..................... 264 560 124 (948) (b) --
Total revenues..................... 2,579 1,426 175 (936) 3,244
Depreciation and amortization......... 264 7 11 -- 282
Net interest charges.................. 122 11 105 (35) (b) 203
Income taxes.......................... 159 (31) (26) -- 102
Income before cumulative effect of
accounting change.................. 227 (44) (44) -- 139
Net income............................ 328 (43) (44) -- 241
Total assets.......................... 29,649 2,449 1,421 -- 33,519
Property additions.................... 118 79 27 -- 224
March 31, 2002
--------------
External revenues..................... $ 1,995 $ 638 $ 214 $ 6 (a) $ 2,853
Internal revenues..................... 355 410 117 (882) (b) --
Total revenues..................... 2,350 1,048 331 (876) 2,853
Depreciation and amortization......... 244 7 12 -- 263
Net interest charges.................. 161 10 122 (14) (b) 279
Income taxes.......................... 162 (41) (27) -- 94
Net income (loss)..................... 198 (60) (22) -- 116
Total assets.......................... 29,147 2,706 6,288 (836) (b) 37,305
Property additions.................... 144 37 14 -- 195
<FN>
Reconciling adjustments to segment operating results from internal management
reporting to consolidated external financial reporting:
(a) Principally fuel marketing revenues which are reflected as reductions to
expenses for internal management reporting purposes.
(b) Elimination of intersegment transactions.
(c) Amounts revised in 2002 - See Note 1.
</FN>
13
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
--------------------------------
2003 2002
- ----------------------------------------------------------------------------------------------------------------
Revised
(See Note 1)
(In thousands, except per share amounts)
REVENUES:
Electric utilities........................................................ $2,315,064 $2,053,976
Unregulated businesses.................................................... 929,408 799,302
---------- ----------
Total revenues........................................................ 3,244,472 2,853,278
---------- ----------
EXPENSES:
Fuel and purchased power.................................................. 1,182,110 684,840
Purchased gas............................................................. 229,465 206,227
Other operating expenses.................................................. 929,239 1,037,751
Provision for depreciation and amortization............................... 281,662 262,828
General taxes............................................................. 178,282 171,988
---------- ----------
Total expenses........................................................ 2,800,758 2,363,634
---------- ----------
INCOME BEFORE INTEREST AND INCOME TAXES...................................... 443,714 489,644
---------- ----------
NET INTEREST CHARGES:
Interest expense.......................................................... 200,650 260,465
Capitalized interest...................................................... (9,152) (5,814)
Subsidiaries' preferred stock dividends................................... 11,242 24,071
---------- ----------
Net interest charges.................................................. 202,740 278,722
---------- ----------
INCOME TAXES................................................................. 102,136 94,429
---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE......................... 138,838 116,493
Cumulative effect of accounting change (net of income taxes of
$72,516,000) (Note 5)..................................................... 102,147 --
---------- ----------
NET INCOME................................................................... $ 240,985 $ 116,493
========== ==========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before cumulative effect of accounting change...................... $0.47 $0.40
Cumulative effect of accounting change (net of income taxes) (Note 5)..... 0.35 --
------ ------
Net income................................................................ $0.82 $0.40
===== =====
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING.......................... 293,886 292,791
======= =======
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before cumulative effect of accounting change...................... $0.47 $0.40
Cumulative effect of accounting change (net of income taxes) (Note 5)..... 0.35 --
------ -----
Net income................................................................ $0.82 $0.40
===== =====
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING........................ 294,877 294,344
======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK................................. $0.375 $0.375
====== ======
<FN>
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these statements.
</FN>
14
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- -----------
(In thousands)
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents................................................. $ 290,036 $ 196,301
Receivables-
Customers (less accumulated provisions of $55,945,000 and $52,514,000
respectively, for uncollectible accounts)............................. 1,149,390 1,153,486
Other (less accumulated provisions of $12,596,000 and $12,851,000,
respectively, for uncollectible accounts)............................. 439,605 473,106
Materials and supplies, at average cost-
Owned................................................................... 255,950 253,047
Under consignment....................................................... 159,268 174,028
Other..................................................................... 289,588 203,630
----------- -----------
2,583,837 2,453,598
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................................ 21,061,059 20,372,224
Less--Accumulated provision for depreciation.............................. 9,047,427 8,551,427
----------- -----------
12,013,632 11,820,797
Construction work in progress............................................. 963,422 859,016
----------- -----------
12,977,054 12,679,813
----------- -----------
INVESTMENTS:
Capital trust investments................................................. 1,042,143 1,079,435
Nuclear plant decommissioning trusts...................................... 1,060,994 1,049,560
Letter of credit collateralization........................................ 277,763 277,763
Other..................................................................... 899,551 918,874
----------- -----------
3,280,451 3,325,632
----------- -----------
DEFERRED CHARGES:
Regulatory assets......................................................... 7,949,286 8,323,001
Goodwill.................................................................. 5,855,494 5,896,292
Other..................................................................... 872,625 902,437
----------- -----------
14,677,405 15,121,730
----------- -----------
$33,518,747 $33,580,773
=========== ===========
15
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- -----------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... $ 1,630,227 $ 1,702,822
Short-term borrowings..................................................... 855,327 1,092,817
Accounts payable.......................................................... 885,651 918,268
Accrued taxes............................................................. 552,853 456,178
Other..................................................................... 987,004 1,000,415
----------- -----------
4,911,062 5,170,500
----------- -----------
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................................................... 6,119,286 6,120,341
Accumulated other comprehensive loss.................................... (657,411) (663,236)
Retained earnings....................................................... 1,842,283 1,711,457
Unallocated employee stock ownership plan common stock -
3,613,860 and 3,966,269 shares, respectively (71,662) (78,277)
----------- -----------
Total common stockholders' equity................................... 7,262,260 7,120,049
Preferred stock of consolidated subsidiaries-
Not subject to mandatory redemption..................................... 335,123 335,123
Subject to mandatory redemption......................................... 18,519 18,521
Subsidiary-obligated mandatorily redeemable preferred securities.......... 409,971 409,867
Long-term debt............................................................ 11,038,490 10,872,216
----------- -----------
19,064,363 18,755,776
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 2,405,174 2,367,997
Accumulated deferred investment tax credits............................... 230,046 235,758
Asset retirement obligation............................................... 1,126,786 --
Nuclear plant decommissioning costs....................................... -- 1,254,344
Power purchase contract loss liability.................................... 3,015,816 3,136,538
Retirement benefits....................................................... 1,643,501 1,564,930
Other..................................................................... 1,121,999 1,094,930
----------- -----------
9,543,322 9,654,497
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
----------- -----------
$33,518,747 $33,580,773
=========== ===========
<FN>
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these balance sheets.
</FN>
16
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
----------------------------
2003 2002
- -------------------------------------------------------------------------------------------------------------------
Revised
(See Note 1)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 240,985 $ 116,493
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation and amortization................................ 281,662 262,828
Nuclear fuel and lease amortization........................................ 14,918 20,965
Other amortization, net.................................................... (4,613) (3,537)
Deferred costs recoverable as regulatory assets............................ (38,748) (70,134)
Deferred income taxes, net................................................. 40,619 (20,534)
Investment tax credits, net................................................ (6,259) (6,746)
Cumulative effect of accounting change (Note 5)............................ (174,663) --
Receivables................................................................ 1,602 60,095
Materials and supplies..................................................... 11,413 18,163
Accounts payable........................................................... (18,915) (3,004)
Accrued taxes.............................................................. 98,896 82,297
Accrued interest........................................................... 89,599 86,579
Deferred rents & sale/leaseback............................................ 3,558 71,438
Prepayments & other........................................................ (69,673) 109,551
Other...................................................................... (8,119) (260,370)
--------- ---------
Net cash provided from operating activities.............................. 462,262 464,084
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt............................................................. 297,696 105,031
Short-term borrowings, net................................................. -- 115,556
Redemptions and Repayments-
Preferred stock............................................................ -- (185,299)
Long-term debt............................................................. (200,866) (183,905)
Short-term borrowings, net................................................. (237,490) --
Common stock dividend payments............................................... (110,159) (109,726)
--------- ---------
Net cash provided from (used for) financing activities................... (250,819) (258,343)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (224,419) (195,292)
Avon cash and cash equivalents previously held for sale (Note 3)............. -- 411,822
Net assets held for sale..................................................... -- (61,565)
Proceeds from nonutility generation trusts................................... 106,327 34,208
Proceeds from assets sale.................................................... 60,572 --
Cash investments............................................................. 24,715 (4,343)
Other........................................................................ (84,903) 36,968
--------- ---------
Net cash provided from (used for) investing activities................... (117,708) 221,798
--------- ---------
Net increase in cash and cash equivalents....................................... 93,735 427,539
Cash and cash equivalents at beginning of period................................ 196,301 220,178
--------- ---------
Cash and cash equivalents at end of period...................................... $ 290,036 $ 647,717
========= =========
<FN>
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.
</FN>
17
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of
Directors of FirstEnergy Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy
Corp. and its subsidiaries as of March 31, 2003, and the related consolidated
statements of income and cash flows for the three-month periods ended March 31,
2003 and 2002. These interim 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 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.
As discussed in Note 1 to the consolidated financial statements, the Company has
revised the presentation of its Consolidated Statement of Income for the quarter
ended March 31, 2002.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholders' equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained references to the Company's change
in its method of accounting for goodwill in 2002 as discussed in Note 2(E) to
those consolidated financial statements and the Company's revised presentation
of its Consolidated Statement of Income for the year ended December 31, 2002 as
discussed in Note 2(L) to those consolidated financial statements) dated
February 28, 2003, except as to Note 2(L) and Note 3, which are as of May 9,
2003, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
consolidated balance sheet as of December 31, 2002, is fairly stated in all
material respects in relation to the consolidated balance sheet from which it
has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
18
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), the
availability and cost of capital, our ability to accomplish or realize
anticipated benefits from strategic initiatives and other similar factors.
FirstEnergy Corp. is a registered public utility holding company that
provides regulated and competitive energy services (see Results of Operations -
Business Segments) domestically and internationally. The international
operations were acquired as part of FirstEnergy's acquisition of GPU, Inc. in
November 2001. GPU Capital, Inc. and its subsidiaries provide electric
distribution services in foreign countries. GPU Power, Inc. and its subsidiaries
develop, own and operate generation facilities in foreign countries. Sales are
planned but not pending for the remaining international operations (see Capital
Resources and Liquidity). Regulated electric distribution services are provided
in Ohio by wholly owned subsidiaries (Ohio electric utilities) - Ohio Edison
Company (OE), The Cleveland Electric Illuminating Company (CEI), and The Toledo
Edison Company (TE). Regulated services are provided in Pennsylvania through
wholly owned subsidiaries (Pennsylvania electric utilities) - Metropolitan
Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec) and
Pennsylvania Power Company (Penn) - a wholly owned subsidiary of OE. Jersey
Central Power & Light Company (JCP&L) provides electric distribution services in
New Jersey. Transmission services are provided in the franchise areas of the
Ohio electric utilities and Penn by wholly owned subsidiary American
Transmission Systems, Inc. (ATSI). Transmission services are provided by Met-Ed,
Penelec and JCP&L in their respective franchise areas. The coordinated delivery
of energy and energy-related products, including electricity, natural gas and
energy management services, to customers in competitive markets is provided
through a number of subsidiaries. Subsidiaries providing competitive services
include FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services
Group, LLC (FSG), MARBEL Energy Corporation and MYR Group, Inc.
Results of Operations
- ---------------------
Net income in the first quarter of 2003 was $241.0 million or $0.82
per share of common stock (basic and diluted), compared to $116.5 million or
$0.40 per share of common stock (basic and diluted) in the first quarter of
2002. Net income in the first quarter of 2003 included an after-tax credit of
$102.1 million resulting from the cumulative effect of an accounting change due
to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143,
"Accounting for Asset Retirement Obligations." Income before the cumulative
effect of an accounting change was $138.8 million in the first three months of
2003, or $0.47 per share of common stock (basic and diluted). Results in the
first quarter of 2003, before the accounting change, benefited from increased
revenues due to cold weather, increased gas margins, and reduced financing
costs. Partially offsetting these favorable factors were higher employee benefit
expenses and incremental costs (which reduced basic and diluted earnings per
share by $0.18) related to the extended outage at the Davis-Besse nuclear plant
(see Davis-Besse Restoration).
Reclassifications of Previously Reported Income Statement
FirstEnergy recorded an increase to income during the three months
ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million)
relative to its decision to retain an interest in the Avon Energy Partners
Holdings (Avon) business previously classified as held for sale - see Note 3.
This amount represents the aggregate results of operations of Avon for the
period this business was held for sale. It was previously reported on the
Consolidated Statement of Income as the cumulative effect of a change in
accounting. In April 2003, it was determined that this amount should instead
have been classified in operations. As further discussed in Note 3, the decision
to retain Avon was made in the first quarter of 2002 and Avon's results of
operations for that quarter have been classified in their respective revenue and
expense captions on the Consolidated Statement of Income. This change in
classification had no effect on previously reported net income. The effects of
this change on the Consolidated Statement of Income previously reported for the
three months ended March 31, 2002 are shown in Note 1.
In June 2002, the Emerging Issues Task Force (EITF) reached a partial
consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." Based on the EITF's partial consensus position, for
periods after July 15,
19
2002, mark-to-market revenues and expenses and their related kilowatt-hour sales
and purchases on energy trading contracts must be shown on a net basis in the
Consolidated Statements of Income. FirstEnergy had previously reported such
contracts as gross revenues and purchased power costs. Therefore, revenues and
expenses for the first quarter of 2002 have been reclassified (see
Implementation of Recent Accounting Standard).
Revenues
Total revenues increased $391.2 million in the first quarter of 2003,
compared to the same period last year as a result of additional sales in
FirstEnergy's regulated and competitive service segments. Electric and gas sales
revenue increased due to colder than normal weather in the first quarter of 2003
compared to milder than normal weather in the first three months of 2002.
Sources of changes in revenues during the first quarter of 2003 compared to the
first quarter of 2002 are summarized in the following table:
Sources of Revenue Changes
------------------------------------------------------
Increase (Decrease) (In millions)
Electric Utilities (Regulated Services):
Retail electric sales.................. $ 108.2
Wholesale electric sales .............. 139.5
All other revenues..................... 13.4
---------------------------------------------------
Total Electric Utilities................. 261.1
---------------------------------------------------
Unregulated Businesses (Competitive Services):
Retail electric sales.................. 66.7
Wholesale electric sales............... 233.8
Gas sales.............................. 43.9
FSG.................................... (42.4)
Other.................................. (8.9)
---------------------------------------------------
Total Unregulated Businesses............. 293.1
---------------------------------------------------
International............................ (162.3)
Other.................................... (0.7)
---------------------------------------------------
Net Revenue Increase..................... $ 391.2
===================================================
Electric Sales
Retail sales by FirstEnergy's electric utility operating companies
(EUOC) increased by $108.2 million in the first quarter of 2003 compared to the
first quarter of 2002. Temperatures in the EUOC service areas ranged from 20% to
30% colder in the first quarter of 2003, compared to the same period last year,
increasing residential and commercial heating loads.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the same quarter of 2002 are summarized in the
following table:
Changes in Kilowatt-hour Sales
------------------------------------------------
Increase (Decrease)
Electric Generation Sales:
Retail -
Regulated services.............. 2.1%
Competitive services............ 130.2%
Wholesale....................... 141.3%
-------------------------------------------------
Total Electric Generation Sales..... 30.6%
=================================================
EUOC Distribution Deliveries:
Residential....................... 15.4%
Commercial........................ 11.7%
Industrial........................ 1.3%
-------------------------------------------------
Total Distribution Deliveries....... 9.4%
=================================================
Shopping by customers for alternative energy suppliers and the effect
of a sluggish national economy in FirstEnergy's service areas combined to reduce
regulated retail generation sales revenue by $4.7 million in the first quarter
of 2003 from the same period in 2002, despite the colder weather in 2003. Sales
of electric generation by alternative suppliers in Ohio, Pennsylvania and New
Jersey in the first quarter of 2003 increased by 8.8, 4.4 and 0.8 percentage
points, respectively, or 5.8 percentage points on a consolidated basis from the
first quarter of 2002.
20
Revenues from distribution deliveries increased by $127.2 million or
11.2% in the first quarter of 2003 compared to the first quarter of 2002 largely
due to the colder temperatures. Increased kilowatt-hour deliveries resulted from
additional demand from all three customer segments: residential, commercial and
industrial. The slower industrial growth continued to reflect sluggish economic
conditions.
Partially offsetting the increase in revenues from distribution
deliveries were Ohio transition plan incentives provided to customers to promote
customer shopping for alternative suppliers - $14.4 million of additional
credits in the first quarter of 2003 compared to the same period in 2002. These
reductions in revenue are deferred for future recovery under the Ohio transition
plan and do not materially affect current period earnings.
EUOC sales to wholesale customers increased by $139.5 million in the
first quarter of 2003 from the same quarter last year. The increase occurred
almost entirely at JCP&L and resulted from the auction of its entire basic
generation service (BGS) responsibility to alternative suppliers. At the
direction of the New Jersey Board of Public Utilities (NJBPU), JCP&L is selling
its pre-existing sources of power supply, including energy provided by
non-utility generation (NUG) contracts, into the wholesale market.
Electric generation sales by FirstEnergy's competitive segment
increased $300.5 million in the first quarter of 2003 from the first quarter of
2002, primarily from additional sales to the wholesale market ($233.8 million)
as FES began supplying a portion of New Jersey's BGS requirements in September
2002. Retail sales by FirstEnergy's competitive services segment increased by
$66.7 million from kilowatt-hour sales that were more than double the prior
year's level. That increase resulted in part from retail customers switching to
FES, under Ohio's electricity choice program. The higher kilowatt-hour sales in
Ohio were partially offset by lower retail sales in markets outside of Ohio.
FirstEnergy's regulated and unregulated subsidiaries record purchase
and sales transactions with PJM Interconnection ISO, an independent system
operator, on a gross basis in accordance with EITF 99-19, "Reporting Revenue
Gross as a Principal versus Net as an Agent." This gross basis classification of
revenues and costs may not be comparable to other energy companies that operate
in regions that have not established ISOs and do not meet EITF 99-19 criteria.
The aggregate purchase and sales transactions for the three months ended March
31, 2003 and 2002 are summarized as follows:
Three Months Ended
March 31,
----------------------
2003 2002
- --------------------------------------------
(In millions)
Sales.............. $336 $46
Purchases.......... 361 80
- -------------------------------------------
FirstEnergy's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from the PJM ISO from power sales
(as reflected in the table above) during periods when it had additional
available power capacity. Revenues also include sales by FirstEnergy of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when it required additional power to meet FirstEnergy's retail load
requirements and, secondarily, to sell to the wholesale market.
International revenues declined $162.3 million due to the sale of a
79.9% interest in Avon during the second quarter of 2002 and the subsequent
application of equity accounting to FirstEnergy's remaining 20.1% interest. As a
result, no revenues were recorded for FirstEnergy's equity interest in Avon in
the first quarter of 2003.
Nonelectric Sales
Nonelectric sales revenues of the competitive services segment
declined by $7.4 million in the first quarter of 2003 from the same period in
2002. Reduced revenues from FSG were substantially offset by higher natural gas
sales revenues resulting from a weather-stimulated increase in prices in the
first three months of 2003. The reduced revenues from FSG also reflected the
sales in early 2003 of Colonial Mechanical and Webb Technologies, as well as
continued declines associated with weak economic conditions.
21
Expenses
Total expenses increased $437.1 million in the first quarter of 2003
from the same quarter of 2002. Sources of changes in expenses in the first
quarter of 2003 from the first quarter of 2002 are summarized in the following
table:
Sources of Expense Changes
- -----------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power $ 497.3
Purchased gas 23.2
Other operating expenses (108.5)
Depreciation and amortization 18.8
General taxes 6.3
- -----------------------------------------------------
Net Expense Increase $ 437.1
=====================================================
The net increase in expenses in the first quarter of 2003 compared to
the first quarter of 2002 was primarily due to a $510.2 million increase in
purchased power costs. The increase resulted from additional volumes to cover
supply obligations assumed by FES for sales to the New Jersey market to provide
BGS, and additional supplies required to replace Davis-Besse power during its
extended outage (see Davis-Besse Restoration). The extended outage at the
Davis-Besse nuclear plant produced a decline in nuclear generation of 16.7% in
the first quarter of 2003, compared to the first quarter of 2002. Purchased gas
costs increased by $23.2 million in the first quarter of 2003 compared to the
same period of 2002 due to higher unit costs, partially offset by lower volumes
purchased to meet reduced sales levels. Despite reduced quantities of gas sold,
gross profit margins improved by $18.5 million during the first quarter of 2003,
compared to the same period last year.
Other operating expenses decreased $108.5 million in the first
quarter of 2003 from the first quarter of 2002. The decrease primarily resulted
from reduced business volume from domestic energy-related businesses which
lowered other operating expenses by $66.1 million, reduced international
expenses of $72.5 million (due to the sale of Avon) and the absence of one-time
charges recorded in the first quarter of 2002 of $78.2 million. The reduced
volume of energy-related business reflected the sale in early 2003 of the
Colonial Mechanical and Webb Technologies businesses, as well as continued
declines associated with weak economic conditions. Partially offsetting these
lower expenses were $36.3 million of additional nuclear costs resulting from the
Davis-Besse extended outage and $50.4 million in higher employee benefit costs.
Charges for depreciation and amortization increased by $18.8 million
in the first quarter of 2003 compared to the first quarter of 2002. The higher
charges primarily resulted from three factors - increased amortization of the
Ohio transition regulatory assets ($28.8 million), recognition of depreciation
on four fossil plants ($9.6 million) which had been held pending sale in the
first quarter of 2002, but were subsequently retained by FirstEnergy in the
fourth quarter of 2002, and reduced tax related deferrals in 2003 ($7.9
million). Partially offsetting these increases in depreciation and amortization
were higher shopping incentive deferrals in Ohio ($14.4 million) and lower
charges resulting from the implementation of SFAS 143 ($11.6 million), including
revised service life assumptions for generating plants ($8.0 million).
Net Interest Charges
Net interest charges decreased $76.0 million in the first quarter of
2003 compared to the same period of 2002. FirstEnergy's redemption and
refinancing of its outstanding debt and preferred stock over the last twelve
months, resulted in a $57.1 million reduction of financing costs. In addition,
the sale of FirstEnergy's 79.9% interest in Avon eliminated $18.9 million of
financing costs. Redemption and refinancing activities during the first quarter
of 2003 totaled $122 million (excluding net reductions to various revolving bank
facilities) and $563 million, respectively, and are expected to result in
annualized savings of approximately $20 million. Partially offsetting these
savings were $2.4 million of incremental interest costs associated with the
issuance of $250 million of new senior notes. FirstEnergy also exchanged
existing fixed-rate payments on outstanding debt (principal amount of $700
million as of March 31, 2003) for short-term variable rate payments through
interest rate swap transactions (see Market Risk Information - Interest Rate
Swap Agreements below). Net interest charges were reduced by $6.9 million in the
first quarter of 2003, compared to the first quarter of 2002 as a result of
these swaps.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 (see discussion further below) in the first
quarter of 2003, FirstEnergy recorded an after-tax credit to net income of
$102.1 million. FirstEnergy identified applicable legal obligations as defined
under the new standard for nuclear power plant decommissioning and reclamation
of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting
SFAS 143 in January 2003, asset retirement costs of $602 million were recorded
22
as part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $415 million. The asset retirement obligation (ARO)
liability at the date of adoption was $1.109 billion, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning
liabilities of $1.232 billion, including unrealized gains on decommissioning
trust funds of $12 million. FirstEnergy expects substantially all of its nuclear
decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in
rates over time. Therefore, FirstEnergy recognized a regulatory liability of
$185 million upon adoption of SFAS 143 for the transition amounts related to
establishing the ARO for nuclear decommissioning for those companies. The
remaining cumulative effect adjustment for unrecognized depreciation and
accretion offset by the reduction in the liabilities was a $174.6 million
increase to income, or $102.1 million net of income taxes. Unrealized gains on
decommissioning trust investments ($7 million net of tax) formerly included in
the decommissioning liability balances as of December 31, 2002 were offset
against Other Comprehensive Income (OCI) upon the adoption of SFAS 143 (see Note
5).
Earnings Effect of SFAS 143
In June 2001, the FASB issued SFAS 143. The new statement provides
accounting standards for retirement obligations associated with tangible
long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Over time the capitalized costs are depreciated and the present value of the
asset retirement liability increases, resulting in a period expense. However,
rate-regulated entities may recognize a regulatory asset or liability instead,
if the criteria for such treatment are met. Upon retirement, a gain or loss
would be recorded if the cost to settle the retirement obligation differs from
the carrying amount.
In the first quarter of 2003, application of SFAS 143 (excluding the
cumulative adjustment recorded upon adoption -- See Note 5 ) resulted in the
following changes to income and expense categories:
Effect of SFAS 143 -- First Quarter 2003
----------------------------------------
Increase (decrease) (millions)
Other operating expense
-----------------------
Cost of removal (previously included in depreciation).... $ 4.2
Depreciation
------------
Replacement of decommissioning expense................... (22.4)
Depreciation of asset retirement cost.................... 1.9
Accretion of asset retirement liability.................. 9.9
Reclassification of cost of removal to expense .......... (3.9)
----------------------------------------------------------------------
Net impact to depreciation............................... (14.5)
----------------------------------------------------------------------
Other Income
------------
Earnings on trust balances............................... 2.5
---------------------------------------------------------------------
Income taxes............................................. 5.3
---------------------------------------------------------------------
Net income effect........................................ $7.5
=====================================================================
Postretirement Plans
Sharp declines in equity markets since the second quarter of 2000 and
a reduction in FirstEnergy's assumed discount rate for pensions and other
postretirement obligations have combined to produce a significant increase in
those costs. Also, increases in health care payments and a related increase in
projected trend rates have led to higher health care costs. Combined, these
employee benefit expenses increased $49.2 million in the first quarter of 2003
compared to the same period in 2002. The following table summarizes the net
pension and other post-employment benefits (OPEB) expense (excluding amounts
capitalized) for the three months ended March 31, 2003 and 2002.
Three Months Ended
Postretirement Expense (Income) March 31,
--------------------------------------------------------
2003 2002
---- ----
(In millions)
Pension...................... $31.3 $(3.8)
OPEB......................... 40.5 26.4
- --------------------------------------------------------
Total...................... $71.8 $22.6
========================================================
23
The pension and OPEB expense increases are included in various cost
categories and have contributed to other cost increases discussed above. See
"Significant Accounting Policies - Pension and Other Postretirement Benefits
Accounting" for a discussion of the impact of underlying assumptions on
postretirement expenses.
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 franchise customers who have not chosen an alternative generation
supplier. The Ohio electric utilities and Penn obtain generation through a power
supply agreement with the competitive services segment (see Outlook - Business
Organization). The competitive services segment also supplies a substantial
portion of the "provider of last resort" (PLR) requirements for Met-Ed and
Penelec under contract. The competitive services segment includes all
competitive energy and energy-related services including commodity sales (both
electricity and natural gas) in the retail and wholesale markets, marketing,
generation, trading and sourcing of commodity requirements, as well as other
competitive energy services such as heating, ventilating and air-conditioning.
Financial results discussed below include intersegment revenues. 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 $328.3 million in the first quarter of 2003,
compared to $197.9 million in the first quarter of 2002. The factors
contributing to the changes in net income are summarized in the following table:
Regulated Services
--------------------------------------------------------
Increase (Decrease) (In millions)
Revenues................................. $230.0
Expenses................................. 242.3
------------------------------------------------------
Income Before Interest and Income Taxes.. (12.3)
Net interest charges..................... (39.2)
Income taxes............................. (2.5)
-------------------------------------------------------
Income Before Cumulative Effect of a
Change in Accounting..................... 29.4
Cumulative effect of a change in accounting 101.0
------------------------------------------------------
Net Income............................... $130.4
======================================================
Higher generation sales and distribution deliveries combined to
increase external revenues by $247.7 million in the first quarter of 2003
compared to the same quarter of 2002. This increase was partially offset by a
$31.1 million decline in revenues from lower sales to FES, resulting from the
extended outage of the Davis-Besse nuclear plant, which decreased generation
available for sale. The remaining change in sales resulted from an increase in
energy-related revenues. The increase in expenses resulted principally from a
$205.8 million increase in purchased power costs due to higher generation sales.
Other operating expenses increased $14.9 million and depreciation and
amortization expense was $19.9 million higher in the first quarter of 2003
compared to the same quarter last year. The increase in other operating expenses
reflected additional employee benefit costs offset in part by the absence in the
first quarter of 2003 of adjustments related to OE's low income housing
investment and lower energy delivery costs. The increase in depreciation and
amortization expense primarily resulted from three factors - increased
amortization of the Ohio transition regulatory assets ($28.8 million),
recognition of depreciation on four fossil plants ($9.6 million) which had been
pending sale in the first quarter of 2002, but were subsequently retained by
FirstEnergy in the fourth quarter of 2002 and the termination of tax related
deferrals in February 2003 ($7.9 million). Partially offsetting these increases
in depreciation and amortization were higher incentive deferrals in Ohio ($14.4
million) and lower charges resulting from the implementation of SFAS 143 ($11.6
million), including revised service life assumptions for generating plants ($8.0
million).
Competitive Services
Net losses decreased to $43.1 million in the first quarter of 2003,
compared to $59.6 million in the first quarter of 2002. The factors contributing
to the reduced loss are summarized in the following table:
24
Competitive Services
-------------------------------------------------------
Increase (Decrease) (In millions)
Revenues................................... $ 377.8
Expenses................................... 351.4
------------------------------------------------------
Income Before Interest and Income Taxes.... 26.4
------------------------------------------------------
Net interest charges....................... 1.0
Income taxes............................... 10.1
------------------------------------------------------
Income Before Cumulative Effect of a
Change in Accounting..................... 15.3
Cumulative effect of a change in accounting 1.2
------------------------------------------------------
Net Income................................. $ 16.5
======================================================
The increase in revenues in the first quarter of 2003, compared to
the first quarter of 2002, includes the net effect of several factors. Revenues
from the electric wholesale market increased $233.8 million in the first quarter
of 2003 from the same period last year as kilowatt-hour sales more than doubled
resulting principally from sales as an alternative supplier for a portion of New
Jersey's BGS requirements. Retail kilowatt-hour sales revenues increased $66.7
million as a result of expanding the FES business in Ohio under Ohio's
electricity choice program and higher weather stimulated sales to existing
customers. Natural gas sales were $43.9 million higher due to higher prices
resulting from colder weather in the first quarter of 2003, compared to the same
period last year. Internal sales to the regulated services segment increased
$90.3 million primarily reflecting sales to Met-Ed and Penelec in supplying a
substantial portion of their PLR requirements in Pennsylvania. Energy-related
services such as heating, ventilating and air-conditioning work reflected the
divestiture in early 2003 of Colonial Mechanical and Webb Technologies, as well
as continued declines associated with weak economic conditions. Revenues from
energy-related services decreased $69.9 million in the first quarter of 2003
from the first quarter of 2002.
Expenses increased $351.4 million in the first quarter of 2003 from
the same period of 2002 primarily attributable to purchased power costs, which
increased $405.8 million to source the higher kilowatt-hour sales to wholesale
and retail customers. Gas costs also increased in the first quarter of 2003 by
$23.2 million, reflecting higher unit costs during the colder than normal
weather compared to the first quarter of 2002. Partially offsetting these
factors were lower costs due to reduced business volume for domestic
energy-related businesses of $61.1 million and other operating expenses which
decreased $17.5 million. The decrease in other operating costs reflected the
absence of $65.6 million of one-time charges in the first quarter of 2002,
partially offset by higher nuclear production costs from the extended
Davis-Besse outage and increased employee benefit costs (principally pension and
health care).
Capital Resources and Liquidity
- -------------------------------
FirstEnergy's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without increasing FirstEnergy's net debt and
preferred stock outstanding. Available borrowing capacity under short-term
credit facilities will be used to manage working capital requirements. Over the
next three years, FirstEnergy expects to meet its contractual obligations with
cash from operations. Thereafter, FirstEnergy expects to use a combination of
cash from operations and funds from the capital markets.
Changes in Cash Position
The primary source of ongoing cash for FirstEnergy, as a holding
company, is cash dividends from its subsidiaries. The holding company also has
access to $1.5 billion of revolving credit facilities. In the first quarter of
2003, FirstEnergy received $137.0 million of cash dividends from its
subsidiaries and paid $110.2 million in cash common stock dividends to its
shareholders. There are no material restrictions on the issuance of cash
dividends by FirstEnergy's subsidiaries.
As of March 31, 2003, FirstEnergy had $290.0 million of cash and cash
equivalents, compared with $196.3 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities during the first
quarter of 2003, compared with the first quarter of 2002 were as follows:
25
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 354 $ 334
Working capital and other............ 108 130
-------------------------------------------------------------
Total................................ $ 462 $ 464
=============================================================
(1)Includes net income, depreciation and
amortization, deferred income taxes, investment
tax credits and major noncash charges.
Net cash provided from operating activities decreased $2 million due
to a $22 million increase in funds used for working capital that was offset in
part by a $20 million increase in cash earnings. The change in funds used for
working capital represents offsetting changes for receivables, sale and
leaseback rent payments, prepayments and other.
Cash Flows From Financing Activities
The following table provides details regarding security issuances and
redemptions during the first quarter of 2003:
Securities Issued or Redeemed in the First Quarter 2003
--------------------------------------------------------------
(In millions)
New Issues
Senior Notes.............................. 250
Long-term revolver........................ 50
Other, primarily debt discount............ (2)
-----
298
Redemptions
First mortgage bonds...................... 40
Pollution control notes................... 50
Secured notes............................. 108
Other, primarily redemption premiums...... 3
----------------------------------------------------------
201
Short-term Borrowings, Net Use of Cash......... 237
----------------------------------------------------------
Net cash flows used for financing activities declined by $8 million
in the first quarter of 2003 from the first quarter of 2002. The decrease in
funds used for financing activities resulted from increased financing of $77
million that exceeded $69 million of additional redemptions and repayments
during the first quarter of 2003 compared to the same period of 2002.
FirstEnergy had approximately $855.3 million of short-term
indebtedness as of March 31, 2003 compared to $1.093 billion at the end of 2002.
Available borrowing capability included $356 million under the $1.5 billion
revolving lines of credit and $76 million under bilateral bank facilities. As of
March 31, 2003, OE, CEI, TE and Penn had the aggregate capability to issue $2.2
billion of additional first mortgage bonds (FMB) on the basis of property
additions and retired bonds. JCP&L, Met-Ed and Penelec no longer issue FMB other
than as collateral for senior notes, since their senior note indentures prohibit
them (subject to certain exceptions) from issuing any debt which is senior to
the senior notes. As of March 31, 2003, JCP&L, Met-Ed and Penelec had the
aggregate capability to issue $443 million of additional senior notes based upon
FMB collateral. Based upon applicable earnings coverage tests and their
respective charters, OE, Penn, TE and JCP&L could issue a total of $4.5 billion
of preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance
of preferred stock.
On March 17, 2003, FirstEnergy filed a registration statement with
the U.S. Securities and Exchange Commission covering securities in the aggregate
amount of up to $2 billion. Although the Company does not have any current plans
to issue securities, the shelf registration provides the flexibility to issue
and sell various types of securities, including common stock, debt securities,
or share purchase contracts and related share purchase units.
On April 21, 2003, OE completed a $325 million refinancing
transaction that included two tranches -- $175 million of 4.00% five year notes
and $150 million of 5.45% twelve year notes. The net proceeds will be used to
redeem approximately $220 million of outstanding OE first mortgage bonds having
a weighted average cost of 7.99%, with the remainder to be used to pay down
short-term debt.
26
On May 1 and May 2, 2003, FirstEnergy executed two fixed-for-floating
interest rate swap agreements with notional values of $50 million each on
underlying senior notes with an average fixed interest rate of 4.73%.
Cash Flows From Investing Activities
Net cash flows used for investing activities totaled $118 million in
the first quarter of 2003, compared to net cash flows of $222 million provided
from investing activities for the same period of 2002. The $340 million change
resulted from the absence of the Avon cash amount recognized in the first
quarter of 2002 resulting from the reclassification from the "Assets Pending
Sale" presentation to normal operations presentation (see Note 3), increased
capital expenditures and other, offset in part by an increase in cash
investments and proceeds from NUG trusts.
The following table summarizes first quarter of 2003 investments by
FirstEnergy's regulated services and competitive services segments:
Summary of First Quarter 2003 Property
Cash Used for Investing Activities Additions Investments Other Total
------------------------------------------------------------------------------
Sources (Uses) (in millions)
Regulated Services................. $(118) $136 (1) $ (8) $ 10
Competitive Services............... (79) 63 (2) (71) (87)
Other.............................. (27) (77) 3 (101)
Eliminations....................... -- -- 60 60
-----------------------------------------------------------------------------
Total......................... $(224) $122 $(16) $(118)
===============================================================================
(1) Includes $106 million proceeds from NUG trusts.
(2) Includes $61 million proceeds from sale of assets.
During the remaining three quarters of 2003, capital requirements for
property additions and capital leases are expected to be approximately $578
million, including $36 million for nuclear fuel. FirstEnergy has additional
requirements of approximately $378 million to meet sinking fund requirements for
preferred stock and maturing long-term debt during the remainder of 2003. These
cash requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on its credit ratings.
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC. Moody's noted that merger debt had put pressure on FirstEnergy's
rating, but that FirstEnergy had plans to reduce debt at all levels within the
company although those plans had been delayed by external events.
Other Obligations
- -----------------
Obligations not included on FirstEnergy's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving Perry Unit 1,
Beaver Valley Unit 2 and the Bruce Mansfield Plant. As of March 31, 2003, the
present value of these sale and leaseback operating lease commitments, net of
trust investments, total $1.5 billion. Also, CEI and TE continue to sell
substantially all of their retail customer receivables, which provided $145
million of financing not included in the Consolidated Balance Sheet as of March
31, 2003.
27
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 March 31, 2003, the maximum potential future payments under
outstanding guarantees and other assurances totaled $960.2 million as summarized
below:
Maximum
Guarantees and Other Assurances Exposure
--------------------------------------------------------------
(In millions)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts(1)...... $ 774.4
Financings (2)(3)........................... 98.3
- -------------------------------------------------------------
872.7
Surety Bonds.................................. 25.8
Rating-Contingent Collateralization (4)....... 61.7
----------------------------------------------------------
Total Guarantees and Other Assurances....... $ 960.2
=============================================================
(1) Issued for a one-year term, with a 10-day termination right
by FirstEnergy.
(2) Includes parental guarantees of subsidiary debt and lease
financing including FirstEnergy's letters of credit supporting
subsidiary debt.
(3) Issued for various terms.
(4) 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 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 FirstEnergy's other assets. The likelihood that such
parental guarantees will increase amounts otherwise paid by FirstEnergy to meet
its obligations incurred in connection with 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 guarantees
provide additional assurance to outside parties that contractual and statutory
obligations will be met in a number of areas including construction contracts,
environmental commitments and various retail transactions.
Various contracts include credit enhancements in the form of cash
collateral, letters of credit or other security in the event of a reduction in
credit rating. Requirements of these provisions vary and typically require more
than one rating reduction to below investment grade by S&P or Moody's to trigger
additional collateralization.
Emdersa Abandonment
- -------------------
On April 18, 2003, FirstEnergy divested its ownership of Emdersa
through the abandonment of its shares in Emdersa's parent company, GPU Argentina
Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's
shares to the independent Board of Directors of GPU Argentina Holdings,
relieving FirstEnergy of all rights and obligations relative to this business.
Prior to the abandonment, FirstEnergy had recorded a foreign currency
translation adjustment (CTA) loss of $90 million through its other comprehensive
income (OCI) - a component of common stockholders' equity. The CTA reduced
FirstEnergy's common stockholders' equity and did not affect its net income. As
a result of the abandonment, FirstEnergy will recognize a one-time, non-cash
charge of $63 million, or $0.21 per share of common stock in the second quarter
of 2003. This charge is the result of realizing the CTA losses through its
current period earnings ($90 million, or $0.30 per share), partially offset by
the gain recognized from eliminating its investment in Emdersa ($27 million, or
$0.09 per share). Since FirstEnergy had previously recorded $90 million of CTA
adjustments in OCI, the net effect of the $63 million charge will be an increase
in common stockholders' equity of $27 million. The $63 million charge does not
include the anticipated income tax benefits related to the abandonment, which
will be fully reserved during the second quarter. FirstEnergy anticipates tax
benefits of approximately $129 million, of which $50 million would increase net
income in the period that it becomes probable those benefits will be realized.
The remaining $79 million of tax benefits would reduce goodwill recognized in
connection with the acquisition of GPU. When
28
realized, the $129 million of tax benefits will represent positive cash flows
for FirstEnergy and increase its common stockholders' equity by $50 million.
Market Risk Information
FirstEnergy uses various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price and interest rate
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, it 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 the first quarter of 2003 is
summarized in the following table:
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
Non-Hedge Hedge Total
- ------------------------------------------------------------------------------------------------
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2003................... $53.8 $ 24.1 $ 77.9
New contract value when entered............................... -- -- --
Additions/Increase in value of existing contracts............. 17.2 29.1 46.3
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. (4.6) (10.3) (14.9)
- -------------------------------------------------------------------------------------------------
Outstanding net asset as of March 31, 2003 (1)................ 66.4 42.9 109.3
- -------------------------------------------------------------------------------------------------
Non-commodity net assets as of March 31, 2003:
Interest Rate Swaps (2)....................................... -- 24.0 24.0
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2003 (3)... $66.4 $ 66.9 $133.3
=================================================================================================
Impact of Changes in Commodity Derivative Contracts (4)
Income Statement Effects (Pre-Tax)............................ $(3.5) $ -- $ (3.5)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $ 18.8 $ 18.8
Regulatory Liability.......................................... $16.1 $ -- $ 16.1
<FN>
(1) Includes $50.3 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 $26.7 million of derivative contract fair value decrease, as of
March 31, 2003, 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.
</FN>
Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
Non-Hedge Hedge Total
- ---------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $ 30.1 $31.1 $ 61.2
Other Liabilities................. (32.4) (2.3) (34.7)
Non-Current-
Other Deferred Charges............ 70.4 38.9 109.3
Other Deferred Credits............ (1.7) (0.8) (2.5)
- ----------------------------------------------------------------------
Net assets........................ $ 66.4 $66.9 $133.3
======================================================================
29
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 uses these
results to develop estimates of fair value for financial reporting purposes and
for internal management decision making. Sources of information for the
valuation of derivative contracts by year are summarized in the following table:
Source of Information
- - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Prices actively quoted(2)............. $12.6 $ 2.6 $ -- $ -- $ -- $15.2
Other external sources(3)............. 26.7 15.8 9.3 -- -- 51.8
Prices based on models................ -- -- -- 6.3 36.0 42.3
- --------------------------------------------------------------------------------------------------------------
Total(4)........................... $39.3 $18.4 $9.3 $6.3 $36.0 $109.3
==============================================================================================================
<FN>
(1) For the last three quarters of 2003.
(2) Exchange traded.
(3) Broker quote sheets.
(4) Includes $50.3 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
</FN>
FirstEnergy performs sensitivity analyses to estimate its exposure to
the market risk of its commodity positions. A hypothetical 10% adverse shift (an
increase or decrease depending on the derivative position) 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 (assets, liabilities and equity) or cash flows as of March 31, 2003.
Based on derivative contracts held as of March 31, 2003, an adverse 10% change
in commodity prices would decrease net income by approximately $4.7 for the next
twelve months.
Interest Rate Swap Agreements
During the first quarter of 2003, FirstEnergy entered into
fixed-to-floating interest rate swap agreements, as part of its ongoing efforts
to manage the interest rate risk of its liability portfolio. These derivatives
are treated as fair value hedges of fixed-rate, long-term debt issues -
protecting against the risk of changes in the fair value of fixed-rate debt
instruments due to lower interest rates. Swap maturities, fixed interest rates
and interest payment dates match those of the underlying obligations. The swap
agreements consummated in the first quarter of 2003 are based on a notional
principal amount of $200 million.
Throughout the second half of 2002 and the first quarter of 2003,
FirstEnergy utilized fixed-to-floating interest rate swap agreements to increase
the variable-rate component of its debt portfolio. As of March 31, 2003, the
debt underlying FirstEnergy's $700 million notional amount of outstanding
fixed-for-floating interest rate swaps had a weighted average fixed interest
rate of 7.10%, which the swaps have effectively converted to a current weighted
average variable interest rate of 3.09%. GPU Power (through a subsidiary) used
existing dollar-denominated interest rate swap agreements in the first quarter
of 2003. The GPU Power agreements convert variable-rate debt to fixed-rate debt
to manage the risk of increases in variable interest rates. GPU Power's swaps
had a weighted average fixed interest rate of 6.68% as of March 31, 2003 and
December 31, 2002. The following summarizes the principal characteristics of the
swap agreements:
Interest Rate Swaps
March 31, 2003 December 31, 2002
----------------------------- -------------------------------
Notional Maturity Fair Notional Maturity Fair
Denomination Amount Date Value Amount Date Value
--------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed to Floating Rate
(Fair value hedges) $200 2006 $ 2.4
350 2023 14.5 $444 2023 $15.5
150 2025 7.9 150 2025 5.9
Floating to Fixed Rate
(Cash flow hedges) $ 13 2005 $(0.8) $ 16 2005 $(0.9)
- ------------------------------------------------------------------------------------------------
30
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $528 million and $532
million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $53 million
reduction in fair value as of March 31, 2003.
Outlook
- -------
FirstEnergy continues to pursue its goal of being the leading
regional supplier of energy and related services in the northeastern quadrant of
the United States, where it sees the best opportunities for growth. Its
fundamental business strategy remains stable and unchanged. While FirstEnergy
continues to build toward a strong regional presence, key elements for its
strategy are in place and management's focus continues to be on execution.
FirstEnergy intends to provide competitively priced, high-quality products and
value-added services - energy sales and services, energy delivery, power supply
and supplemental services related to its core business. As FirstEnergy's
industry changes to a more competitive environment, FirstEnergy has taken and
expects to take actions designed to create a larger, stronger regional
enterprise that will be positioned to compete in the changing energy
marketplace.
FirstEnergy's current focus includes: 1) returning Davis-Besse to
safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio;
3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's
cost structure; 5) enhancing its credit profile and financial flexibility; and
6) achieving earnings growth targets.
Business Organization
FirstEnergy's business is managed as two distinct operating segments
- - a competitive services segment and a regulated services segment. FES provides
competitive retail energy services while the EUOC provide regulated transmission
and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned
subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and
operates those plants. FirstEnergy expects the transfer of ownership of EUOC
non-nuclear generating assets to FGCO will be substantially completed by the end
of the market development period in 2005. All of the EUOC power supply
requirements for the Ohio Companies and Penn are provided by FES to satisfy
their PLR obligations, as well as grandfathered wholesale contracts.
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in the
EUOC's respective state regulatory plans. However, despite these similarities,
the specific approach taken by each state and for each of the EUOCs varies.
Those provisions include:
o allowing the EUOC's electric customers to select their generation
suppliers;
o establishing PLR obligations to non-shopping customers in the
EUOC's service areas;
o allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
o deregulating the EUOC's electric generation businesses; and
o continuing regulation of the EUOC's transmission and distribution
systems.
Regulatory assets are costs that the respective regulatory agencies
have authorized for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. All of the
regulatory assets are expected to continue to be recovered under the provisions
of the respective transition and regulatory plans as discussed below. Regulatory
assets declined $373.7 million to $7.9 billion as of March 31, 2003 from the
balance as of December 31, 2002, with approximately one-half of the decrease
related to the adoption of SFAS 143 by JCP&L, Met-Ed, Penelec and Penn. The
regulatory assets of the individual companies are as follows:
31
Regulatory Assets as of
--------------------------------------------------
March 31, December 31,
Company 2003 2002
--------------------------------------------------
(In millions)
OE.............. $1,775.7 $1,855.9
CEI............. 943.3 939.8
TE.............. 387.1 392.6
Penn............ 77.8 156.9
JCP&L........... 3,094.8 3199.0
Met-Ed.......... 1,126.9 1,179.1
Penelec......... 543.7 599.7
--------------------------------------------------
Total........... $7,949.3 $8,323.0
==================================================
Ohio
FirstEnergy's transition plan (which FirstEnergy filed on behalf of
its Ohio electric utilities) 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 customers.
Customer prices are frozen through a five-year market development period
(2001-2005), except for certain limited statutory exceptions including a 5%
reduction in the price of generation for residential customers. In February
2003, the Ohio electric utilities were authorized increases in revenues
aggregating approximately $50 million (OE - $41 million, CEI - $4 million and TE
- - $5 million) to recover their higher tax costs resulting from the Ohio
deregulation legislation. 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 periods.
New Jersey
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L submitted two rate
filings with the New Jersey Board of Public Utilities (NJBPU) in August 2002.
The first filing requested increases in base electric rates of approximately $98
million annually. The second filing was a request to recover deferred costs that
exceeded amounts being recovered under the current market transition charge and
societal benefits charge (SBC) rates; one proposed method of recovery of these
costs is the securitization of the deferred balance. Hearings began in February
2003. On March 18, 2003, a report prepared by independent auditors addressing
costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was
transmitted to the Office of Administrative Law, where JCP&L's rate case is
being heard. While the auditors concluded that JCP&L's energy procurement
strategy and process was reasonable and prudent, they identified potential
disallowances approximating $17 million. The report subjected $436 million of
deferred costs to a retrospective prudence review during a period of extreme
price uncertainty and volatility in the energy markets. Although JCP&L disagrees
with the potential disallowances, it is pleased with the report's major
conclusions and overall tone. Hearings concluded on April 28, 2003, and initial
briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings
requesting an aggregate rate increase of approximately $122 million in base
electric rates and the recovery of deferred costs based on the securitization
methodology discussed above. If the securitization methodology is not allowed,
then JCP&L has requested deferred cost recovery over a four-year period with a
return on the unamortized deferred cost balance. This alternative would increase
the overall rate request to approximately $246 million. JCP&L strongly disagrees
with many of the positions taken by NJBPU Staff. The Staff's position would
result in a $119 million estimated annual earnings decrease related to the
electricity delivery charge. In addition, the Staff recommended disallowing
approximately $153 million of deferred energy costs which would result in a
one-time pre-tax charge against earnings of $153 million (or $0.31 per share of
common stock). JCP&L will respond to the Staff's position in its Reply Brief
which is due on May 21, 2003. The Administrative Law Judge's recommended
decision is due by the end of June 2003 and the NJBPU's subsequent decision is
due in July 2003.
In 1997, the NJBPU authorized JCP&L to recover from customers,
subject to possible refund, $135 million of costs incurred in connection with a
1996 buyout of a power purchase agreement. JCP&L has recovered the full $135
million; the NJBPU has established a procedural schedule to take further
evidence with respect to the buyout to enable it to make a final prudence
determination contemporaneously with the resolution of the pending rate case.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The results of
the February 2002 auction, with the NJBPU's approval, removed JCP&L's BGS
obligation of 5,100 megawatts for the
32
period August 1, 2002 through July 31, 2003. In February 2003, the auctioning of
BGS for the period beginning August 1, 2003 took place. The auction covered a
fixed price bid (applicable to all residential and smaller commercial and
industrial customers) and an hourly price bid (applicable to all large
industrial customers) process. JCP&L sells all self-supplied energy (NUGs and
owned generation) to the wholesale market with offsets to its deferred energy
cost balances.
Pennsylvania
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to FES through a wholesale power sale which expires in December
2003 and may be extended for each successive calendar year. Under the terms of
the wholesale agreement, FES assumed the supply obligation and the supply profit
and loss risk, for the portion of power supply requirements not self-supplied by
Met-Ed and Penelec under their NUG contracts and other existing power contracts
with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and
Penelec's exposure to high wholesale power prices by providing power at or below
the shopping credit for their uncommitted PLR energy costs during the term of
the agreement to FES. FES has hedged most of Met-Ed's and Penelec's unfilled
on-peak PLR obligation through 2004 and a portion of 2005. Met-Ed and Penelec
will continue to defer those cost differences between NUG contract rates and the
rates reflected in their capped generation rates.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the Commonwealth Court's decision which effectively affirmed the
PPUC's order approving the merger between FirstEnergy and GPU, let stand the
Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and
remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC
remanded the merger savings issue to the Office of Administrative Law for
hearings and directed Met-Ed and Penelec to file a position paper on the effect
of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003.
Because FirstEnergy had already reserved for the deferred energy costs and FES
has largely hedged the anticipated PLR energy supply requirements for Met-Ed and
Penelec through 2005, FirstEnergy, Met-Ed and Penelec believe that the
disallowance of competitive transition charge recovery of PLR costs above
Met-Ed's and Penelec's capped generation rates will not have a future adverse
financial impact during that period.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated
a formal inspection process at the Davis-Besse nuclear plant. This action was
taken in response to corrosion found by FENOC in the reactor vessel head near
the nozzle penetration hole during a refueling outage in the first quarter of
2002. The purpose of the formal inspection process is to establish criteria for
NRC oversight of the licensee's performance and to provide a record of the major
regulatory and licensee actions taken, and technical issues resolved, leading to
the NRC's approval of restart of the plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the first half of the summer of 2003. The NRC must authorize restart
of the plant following its formal inspection process before the unit can be
returned to service. While the additional maintenance work has delayed
FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such
investments in the unit's future safety, reliability and performance to be
essential. Significant delays in Davis-Besse's return to service, which depends
on the successful resolution of the management and technical issues as well as
NRC approval, could trigger an evaluation for impairment of the nuclear plant
(see Significant Accounting Policies below).
Total incremental expenses associated with the extended Davis-Besse
outage in the first quarter of 2003 totaled $88.6 million, including $36.3
million for maintenance work and $52.3 million for fuel and purchased power. It
is anticipated that an additional $13.7 million in maintenance costs will be
expended over the remainder of the Davis-Besse outage. Replacement power costs
are expected to be $15 million per month in the non-summer months and $20-25
million per month during the summer.
FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse through the summer of 2003 and has completed some hedging for the
balance of 2003 as well based on a probabilistic assessment of the unit's
expected start-up date.
33
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $159 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2003 through 2007.
The Companies are required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies believe they are in compliance with the current SO2 and
nitrogen 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 Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit found constitutional and other defects in
the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new
NAAQS rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and will
depend if and how they are ultimately implemented by the states in which the
Companies operate affected facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of Ohio
for which hearings began 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.
Several EUOC 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 March 31, 2003, 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
34
through the SBC. The Companies have total accrued liabilities aggregating
approximately $53.9 million as of March 31, 2003.
The effects of compliance on the EUOC with regard to environmental
matters could have a material adverse effect on FirstEnergy's earnings and
competitive position. These environmental regulations affect FirstEnergy's
earnings and competitive position to the extent it competes with companies that
are not subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations.
FirstEnergy believes it is in material compliance with existing regulations, but
is unable to predict how and when applicable environmental regulations may
change and what, if any, the effects of any such change would be.
Implementation of Recent Accounting Standard
- --------------------------------------------
In June 2002, the EITF reached a partial consensus on Issue No.
02-03. Based on the EITF's partial consensus position, for periods after July
15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour
sales and purchases on energy trading contracts must be shown on a net basis in
the Consolidated Statements of Income. FirstEnergy had previously reported such
contracts as gross revenues and purchased power costs. Comparative quarterly
disclosures and the Consolidated Statements of Income for revenues and expenses
have been reclassified for 2002 to conform with the revised presentation (see
Note 5). In addition, the related kilowatt-hour sales and purchases statistics
described above under Results of Operations were reclassified (1.3 billion
kilowatt-hour in the first quarter of 2002). The following table displays the
impact of changing to a net presentation for FirstEnergy's energy trading
operations.
Impact of Recording Energy Trading Net
on the Previously Reported First Quarter of 2002 Revenues Expenses
- -----------------------------------------------------------------------------
(in millions)
Total before adjustment.............................. $2,893 $2,404
Adjustment........................................... (40) (40)
- -------------------------------------------------------------------------------
Total as reported.................................... $2,853 $2,364
==============================================================================
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 purchase
price allocations for the GPU acquisition were finalized in the fourth quarter
of 2002.
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 - $7.9 billion as of March 31, 2003.
FirstEnergy 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
35
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 postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions 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, the discount rates and health care trend rates used in determining the
projected benefit obligations for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the
end of 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's
pension costs in the first quarter of 2002 were computed assuming a 10.25% rate
of return on plan assets. Beginning in the first quarter of 2003, the assumed
return on plan assets was reduced to 9.00% based upon FirstEnergy's projection
of future returns and pension trust investment allocation of approximately 60%
large cap equities, 10% small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the
36
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends have significantly increased and
will affect future OPEB costs. The 2003 composite health care trend rate
assumption is approximately 10%-12% gradually decreasing to 5% in later years,
compared to the 2002 assumption of approximately 10% in 2002, gradually
decreasing to 4%-6% in later years. In determining its trend rate assumptions,
FirstEnergy included the specific provisions of its health care plans, the
demographics and utilization rates of plan participants, actual cost increases
experienced in its health care plans, and projections of future medical trend
rates.
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, FirstEnergy
evaluates its goodwill for impairment at least annually and would make such an
evaluation more frequently if indicators of impairment should arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value including goodwill, an impairment for goodwill
must be recognized in the financial statements. If impairment were to occur
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 -- fair
value was higher than carrying value for each of its reporting units. The
forecasts used in FirstEnergy's evaluations of goodwill reflect operations
consistent with its general business assumptions. Unanticipated changes in those
assumptions could have a significant effect on FirstEnergy's future evaluations
of goodwill. As of March 31, 2003, FirstEnergy had $5.9 billion of goodwill that
primarily relates to its regulated services segment.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (FirstEnergy's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements, the sale of preferred securities and debt
secured by bondable property, which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46.
FirstEnergy currently consolidates the majority of these entities and
believe it will continue to consolidate following the adoption of FIN 46. In
addition to the entities FirstEnergy is currently consolidating FirstEnergy
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $12.0 million.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS133 for decisions made by the Derivative Implementation Group, as well as
37
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for quarters
which began prior to June 15, 2003, which continue to be applied based on their
original effective dates. FirstEnergy is currently assessing the new standard
and has not yet determined the impact on its financial statements.
38
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
--------------------------
2003 2002
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $742,743 $707,799
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 12,850 14,290
Purchased power.............................................................. 243,828 241,479
Nuclear operating costs...................................................... 125,368 95,234
Other operating costs........................................................ 94,113 79,611
-------- --------
Total operation and maintenance expenses................................... 476,159 430,614
Provision for depreciation and amortization.................................. 105,385 92,130
General taxes................................................................ 48,256 45,376
Income taxes................................................................. 43,254 42,615
-------- --------
Total operating expenses and taxes......................................... 673,054 610,735
-------- --------
OPERATING INCOME................................................................ 69,689 97,064
OTHER INCOME.................................................................... 14,031 512
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 83,720 97,576
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 24,488 33,073
Allowance for borrowed funds used during construction and
capitalized interest (1,380) (621)
Other interest expense....................................................... 2,478 5,147
Subsidiaries' preferred stock dividend requirements.......................... 912 3,626
-------- --------
Net interest charges....................................................... 26,498 41,225
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 57,222 56,351
Cumulative effect of accounting change (net of income taxes of
$22,389,000) (Note 5) 31,720 --
-------- --------
NET INCOME...................................................................... 88,942 56,351
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 659 2,596
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 88,283 $ 53,755
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these statements.
</FN>
39
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
---------- ----------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................. $5,139,199 $4,989,056
Less--Accumulated provision for depreciation............................... 2,573,462 2,552,007
---------- ----------
2,565,737 2,437,049
---------- ----------
Construction work in progress-
Electric plant........................................................... 145,785 122,741
Nuclear fuel............................................................. 47,974 23,481
---------- ----------
193,759 146,222
---------- ----------
2,759,496 2,583,271
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust......................................................... 401,972 402,565
Letter of credit collateralization......................................... 277,763 277,763
Nuclear plant decommissioning trusts....................................... 296,298 293,190
Long-term notes receivable from associated companies....................... 503,510 503,827
Other...................................................................... 70,708 74,220
---------- ----------
1,550,251 1,551,565
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents.................................................. 14,320 20,512
Receivables-
Customers (less accumulated provisions of $5,708,000 and
$5,240,000, respectively for uncollectible accounts)................... 296,218 296,548
Associated companies..................................................... 619,084 592,218
Other (less accumulated provisions of $1,000,000 for uncollectible
accounts at both dates)................................................ 33,430 33,557
Notes receivable from associated companies................................. 264,736 437,669
Materials and supplies, at average cost-
Owned.................................................................... 58,564 58,022
Under consignment........................................................ 20,509 19,753
Prepayments and other...................................................... 26,697 11,804
---------- ----------
1,333,558 1,470,083
---------- ----------
DEFERRED CHARGES:
Regulatory assets.......................................................... 1,853,439 2,012,754
Property taxes............................................................. 59,035 59,035
Unamortized sale and leaseback costs....................................... 72,294 72,294
Other...................................................................... 51,800 51,739
---------- ----------
2,036,568 2,195,822
---------- ---------
$7,679,873 $7,800,741
========== ==========
40
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
---------- ------------
(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
Accumulated other comprehensive loss..................................... (62,548) (65,713)
Retained earnings........................................................ 882,628 807,345
---------- ----------
Total common stockholder's equity.................................... 2,918,809 2,840,361
Preferred stock not subject to mandatory redemption........................ 60,965 60,965
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption...................................... 39,105 39,105
Subject to mandatory redemption.......................................... 13,500 13,500
Long-term debt............................................................. 1,238,877 1,219,347
---------- ----------
4,271,256 4,173,278
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock....................... 526,475 563,267
Short-term borrowings-
Associated companies..................................................... 187 225,345
Other.................................................................... 175,197 182,317
Accounts payable-
Associated companies..................................................... 173,086 145,981
Other.................................................................... 5,380 18,015
Accrued taxes.............................................................. 472,254 467,776
Accrued interest........................................................... 30,646 28,209
Other...................................................................... 100,683 73,882
---------- ----------
1,483,908 1,704,792
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes.......................................... 1,010,863 1,016,680
Accumulated deferred investment tax credits................................ 83,432 86,465
Asset retirement obligation................................................ 302,524 --
Nuclear plant decommissioning costs........................................ -- 292,353
Retirement benefits........................................................ 250,211 247,531
Other...................................................................... 277,679 279,642
---------- ----------
1,924,709 1,922,671
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)............................
---------- ----------
$7,679,873 $7,800,741
========== ==========
<FN>
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these balance sheets.
</FN>
41
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2003 2002
--------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 88,942 $ 56,351
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation and amortization................................ 105,385 92,130
Nuclear fuel and lease amortization........................................ 7,106 11,402
Deferred income taxes, net................................................. 8,683 (13,170)
Investment tax credits, net................................................ (3,580) (3,773)
Cumulative effect of accounting change (Note 5)............................ (54,109) --
Receivables................................................................ (26,409) 64,148
Materials and supplies..................................................... (1,298) (1,642)
Accounts payable........................................................... 14,470 (18,295)
Accrued taxes.............................................................. 4,478 56,884
Accrued interest........................................................... 2,437 6,237
Deferred rents & sale/leaseback............................................ 31,683 31,683
Prepayments & other........................................................ (14,893) 16,095
Other...................................................................... (9,378) (30,539)
--------- ---------
Net cash provided from operating activities.............................. 153,517 267,511
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt............................................................. -- 104,985
Short-term borrowings, net................................................. -- 40,306
Redemptions and Repayments-
Long-term debt............................................................. (19,493) (89,547)
Short-term borrowings, net................................................. (232,278) --
Dividend Payments
Common stock............................................................... (13,000) (101,200)
Preferred stock............................................................ (659) (2,597)
--------- ---------
Net cash provided from (used for) financing activities................... (265,430) (48,053)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (68,367) (30,344)
Notes receivable from associated companies, net.............................. 173,250 (138,181)
Other........................................................................ 838 1,972
--------- ---------
Net cash provided from (used for) investing activities................... 105,721 (166,553)
--------- ---------
Net Increase (decrease) in cash and cash equivalents............................ (6,192) 52,905
Cash and cash equivalents at beginning of period................................ 20,512 4,588
--------- ---------
Cash and cash equivalents at end of period...................................... $ 14,320 $ 57,493
========= =========
<FN>
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these statements.
</FN>
42
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of
Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison
Company and its subsidiaries as of March 31, 2003, and the related consolidated
statements of income and cash flows for the three-month periods ended March 31,
2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
43
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
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
- ---------------------
Earnings on common stock in the first quarter of 2003 increased to
$88.3 million from $53.8 million in the first quarter of 2002. Earnings on
common stock in the first quarter of 2003 included an after-tax credit of $31.7
million from the cumulative effect of an accounting change due to the adoption
of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the
cumulative effect was $57.2 million in the first three months of 2003, compared
to $56.4 million for the same period of 2002. Improved results in the first
quarter of 2003 reflect higher revenues due to colder weather, increased sales
to FES and reduced financing costs, compared with the first quarter of 2002, as
well as the absence of adjustments reflected in the first quarter of 2002 for
OE's low income housing investments. Substantially offsetting these improvements
were higher operating expenses -- primarily nuclear operating costs, employee
benefit costs and depreciation and amortization.
Operating revenues increased by $34.9 million or 4.9% in the first
quarter of 2003 compared with the same period in 2002. The higher revenues
resulted from increased distribution deliveries to residential and commercial
customers due to colder temperatures and additional sales revenues to FES, which
were partially offset by lower generation kilowatt-hour sales to retail
customers. Kilowatt-hour sales to retail customers declined by 1.4% in the first
quarter of 2003 from the same quarter of 2002, which reduced generation sales
revenue by $13.6 million. Electric generation services provided by alternative
suppliers as a percent of total sales delivered in OE's franchise area increased
to 24.0% in the first quarter of 2003 from 17.1% in the first quarter of 2002.
Distribution deliveries increased 7.6% in the first quarter of 2003
compared with the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). This increased revenues from
electricity throughput by $37.6 million in the first quarter of 2003 from the
same quarter of the prior year. Approximately 70% of the increase reflected
higher volumes with the remainder due to higher unit prices. Distribution
deliveries benefited from substantially higher residential and commercial
demand, due in large part to colder temperatures, that was moderated by the
continued effect of a sluggish economy and its impact on demand by industrial
customers in OE's franchise area.
Partially offsetting the increase in revenues from distribution
deliveries were Ohio transition plan incentives provided to customers to promote
customer shopping for alternative suppliers -- $6.3 million of additional
credits in the first quarter of 2003 from the same period last year. These
reductions in revenues 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 $17.3 million
(primarily to FES) in the first quarter of 2003 compared to the same quarter of
2002, due to higher market prices. Increased wholesale revenues occurred despite
a reduction in kilowatt-hour sales in the first quarter of 2003 from the same
quarter last year, due a 9.9% reduction in available nuclear generation from
Beaver Valley Unit 1 as a result of its refueling outage that began on March 8,
2003.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the same quarter of 2002 are summarized in the
following table:
44
Changes in Kilowatt-Hour Sales
---------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. (1.4)%
Wholesale............................... (7.1)%
---------------------------------------------------
Total Electric Generation Sales........... (4.0)%
===================================================
Distribution Deliveries:
Residential............................. 12.2%
Commercial.............................. 8.7%
Industrial.............................. 2.1%
---------------------------------------------------
Total Distribution Deliveries............. 7.6%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $62.3 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ (1.4)
Purchased power costs............................ 2.3
Nuclear operating costs.......................... 30.1
Other operating costs............................ 14.5
--------------------------------------------------------------
Total operation and maintenance expenses....... 45.5
Provision for depreciation and amortization...... 13.3
General taxes.................................... 2.9
Income taxes..................................... 0.6
--------------------------------------------------------------
Total operating expenses and taxes............. $62.3
==============================================================
Lower fuel costs in the first quarter of 2003, compared with the same
quarter of 2002, resulted from reduced nuclear generation. The increased
purchased power costs reflected additional kilowatt-hour purchases offset in
part by lower unit costs. Higher nuclear operating costs occurred in large part
due to the refueling outage at Beaver Valley Unit 1 (100% ownership) in the
first quarter of 2003 compared with refueling outage costs at Beaver Valley Unit
2 (55.6% ownership) in the first quarter of 2002. The increase in other
operating costs reflects higher employee benefit costs and increased
uncollectible customer accounts.
Charges for depreciation and amortization increased by $13.3 million
in the first quarter of 2003 compared to the first quarter of 2002 primarily
from two factors - increased amortization of the Ohio transition regulatory
assets ($19.9 million) and reduced transition plan tax-related deferrals ($6.3
million) in 2003. Partially offsetting these increases were higher shopping
incentive deferrals ($6.6 million) and lower charges resulting from the
implementation of SFAS 143 ($4.7 million), including revised service life
assumptions for generating plants ($1.0 million).
General taxes increased in the first quarter of 2003 from the same
quarter of last year principally due to higher kilowatt-hour taxes in Ohio as
the result of increased kilowatt-hour deliveries.
Other Income
Other income increased by $13.5 million in the first quarter of 2003
from the same period last year, primarily due to the absence in the first
quarter of 2003 of adjustments recorded in the first quarter of 2002 related to
OE's low income housing investments.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $14.7
million in the first quarter of 2003 from the same period last year, reflecting
redemptions and refinancings since the first quarter of 2002. OE's net debt
redemptions totaled $13.0 million during the first quarter of 2003, which will
result in annualized savings of $1.1 million.
45
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded
an after-tax credit to net income of $31.7 million. OE identified applicable
legal obligations as defined under the new standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs
of $133.5 million were recorded as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $25.2 million. The asset
retirement obligation (ARO) liability at the date of adoption was $297.6
million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, OE had
recorded decommissioning liabilities of $292.4 million, including unrealized
gains on the decommissioning trust funds of $10.6 million. Penn expects
substantially all of its nuclear decommissioning costs to be recoverable in
rates over time. Therefore, OE recognized a regulatory liability of $10.6
million upon adoption of SFAS 143 for the transition amounts related to
establishing the ARO for nuclear decommissioning for Penn. The remaining
cumulative effect adjustment for unrecognized depreciation, accretion offset by
the reduction in the existing decommissioning liabilities and ceasing the
accounting practice of depreciating non-regulated generation assets using a cost
of removal component was a $54.1 million increase to income, or $31.7 million
net of income taxes. Unrealized gains on decommissioning trust investments ($6.2
million net of tax) formerly included in the decommissioning liability balances
as of December 31, 2002 were offset against OCI upon the adoption of SFAS 143
(see Note 5).
Capital Resources and Liquidity
- -------------------------------
OE's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
OE expects to meet its contractual obligations with cash from operations.
Thereafter, OE expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, OE had $14.3 million of cash and cash
equivalents, compared with $20.5 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided by operating activities during the first quarter
of 2003, compared with the corresponding period in 2002 were as follows:
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $153 $143
Working capital and other............ 1 125
-------------------------------------------------------------
Total................................ $154 $268
=============================================================
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash from operating activities decreased $114 million due to a
$124 million increase in funds used for working capital -- that decrease was
offset in part by a $10 million increase in cash earnings. The increase in
working capital and other primarily reflects higher accounts receivable from
associated companies in the first quarter of 2003 compared with corresponding
amounts in the first quarter of 2002 ($81 million). A change in accrued tax
liabilities also contributed $52 million to the increase in working capital
primarily due to a $48 million increase in tax payments in the first quarter of
2003 compared with the first quarter of 2002.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash used for financing activities
increased to $265 million from $48 million in the same period last year. The
increase resulted from the absence of new financing and a reduction of debt
(primarily short-term borrowings from associated companies) partially offset by
reduced dividends to FirstEnergy.
OE had approximately $279.1 million of cash and temporary investments
and approximately $175.4 million of short-term indebtedness as of March 31,
2003. Available borrowing capability under bilateral bank facilities totaled
$34.0 million as of March 31, 2002. OE had the capability to issue $1.7 billion
of additional first mortgage bonds on the basis of
46
property additions and retired bonds. Based upon applicable earnings coverage
tests OE could issue up to $3.0 billion of preferred stock (assuming no
additional debt was issued) as of March 31, 2003.
On April 21, 2003, OE completed a $325 million debt refinancing
transaction that included two tranches -- $175 million of 4.00% five year notes
and $150 million of 5.45% twelve year notes. The net proceeds will be used to
redeem approximately $220 million of outstanding OE first mortgage bonds having
a weighted average cost of 7.99%, with the remainder to be used to pay down
short-term debt.
Cash Flows From Investing Activities
Net cash flows received from investing activities totaled $106
million in the first quarter of 2003, compared to a net use of funds of $167
million for the same period of 2002. The $273 million increase in funds from
investing activities resulted from payments received on notes from associated
companies, offset in part by additional capital expenditures.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $113 million,
including $17 million for nuclear fuel. OE has additional requirements of
approximately $234 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including OE.
On April 11, 2003, Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including the OE Companies. Moody's noted that merger debt had put
pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt
at all levels within the company although those plans had been delayed by
external events.
Other Obligations
Obligations not included on OE's Consolidated Balance Sheet primarily
consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver
Valley Unit 2. As of March 31, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $713
million.
Equity Price Risk
- -----------------
Included in OE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $151
million and $148 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $15 million reduction in fair value as of March 31, 2003.
Outlook
- -------
Beginning in 2001, OE's customers were able to select alternative
energy suppliers. OE continues to deliver power to residential homes and
businesses through its existing distribution system, which remains regulated.
Customer rates have been restructured into separate components to support
customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing
responsibility to provide power to those customers not choosing to receive power
from an alternative energy supplier subject to certain limits. Adopting new
approaches to regulation and experiencing new forms of competition have created
new uncertainties.
47
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of OE's Ohio customers elects to obtain
power from an alternative supplier, OE reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive), and the customer receives a generation charge from the
alternative supplier. OE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
Regulatory assets are costs which have been authorized by the Public
Utilities Commission of Ohio (PUCO), Pennsylvania Public Utility Commission and
the Federal Energy Regulatory Commission, for recovery from customers in future
periods and, without such authorization, would have been charged to income when
incurred. Regulatory assets declined $159.4 million to $1.9 billion on March 31,
2003 from the balance as of December 31, 2002, with $10.6 million of the
decrease related to the cumulative entry adopting SFAS 143 at Penn and the
balance of the reduction resulting from recovery of transition plan regulatory
assets. All of the OE Companies' regulatory assets are expected to continue to
be recovered under the provisions of their respective transition plan and rate
restructuring plan. The OE Companies' regulatory assets are as follows:
Regulatory Assets as of
---------------------------------------------------------
March 31, December 31,
Company 2003 2002
---------------------------------------------------------
(In millions)
OE......................... $1,775.6 $1,855.9
Penn....................... 77.8 156.9
---------------------------------------------------------
Consolidated Total...... $1,853.4 $2,012.8
==========================================================
As part of OE's Ohio transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. OE is also
required to provided 560 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. OE's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area. In 2003, the total peak load
forecasted for customers electing to stay with OE, including the 560 MW of low
cost supply and the load served by OE's affiliate is 5,820 MW.
Environmental Matters
OE believes it is in compliance with the current sulfur dioxide (SO2)
and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from OE's Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2C - Environmental
Matters). OE continues to evaluate its compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. OE cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U. S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act (CAA). The civil complaint against OE and Penn
requests installation of "best available control technology" as well as civil
penalties of up to $27,500 per day. Although unable to predict the outcome of
these proceedings, the OE Companies believe the Sammis Plant is in full
compliance with the CAA and that the NOV and complaint are without merit.
Penalties could be imposed if the Sammis Plant continues to operate without
correcting the alleged violations and a court determines that the allegations
are valid. The Sammis Plant continues to operate while these proceedings are
pending.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the
48
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.
OE believes it is 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 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.
The effects of compliance on OE with regard to environmental matters
could have a material adverse effect on its earnings and competitive position.
These environmental regulations affect our earnings and competitive position to
the extent OE competes with companies that are not subject to such regulations
and therefore do not bear the risk of costs associated with compliance, or
failure to comply, with such regulations. OE believes it is in material
compliance with existing regulations, but is unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
Significant Accounting Policies
- -------------------------------
OE 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 OE's 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 those 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 the
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.
As of March 31, 2002, the OE Companies' regulatory assets totaled $1.9 billion.
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.
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 been 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 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
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
49
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.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's
pension costs in 2002 were computed assuming a 10.25% rate of return on plan
assets. As of December 31, 2002 the assumed return on plan assets was reduced to
9.00% based upon FirstEnergy's projection of future returns and pension trust
investment allocation of approximately 60% large cap equities, 10% small cap
equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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 asset
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).
Recently Issued Accounting Standard Not Yet Implemented
- -------------------------------------------------------
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (OE's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
OE currently has transactions which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. OE currently consolidates the majority of these
entities and believe it will continue to consolidate following the adoption of
FIN 46. In addition to the entities it is currently consolidating, OE believes
that the PNBV Capital Trust, which was used to acquire a portion of the
off-balance sheet
50
debt issued in connection with the sale and leaseback of its interest in the
Perry Plant and Beaver Valley Unit 2, would require consolidation as a VIE under
FIN 46. Ownership of the trust includes a three-percent equity interest by a
nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $12.0 million.
51
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
----------------------------
2003 2002
--------- ---------
(In thousands)
OPERATING REVENUES.............................................................. $419,771 $424,977
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 12,659 17,270
Purchased power.............................................................. 136,345 139,436
Nuclear operating costs...................................................... 63,161 71,417
Other operating costs........................................................ 75,809 66,847
-------- --------
Total operation and maintenance expenses................................. 287,974 294,970
Provision for depreciation and amortization.................................. 26,557 28,471
General taxes................................................................ 39,713 38,746
Income taxes................................................................. 9,223 7,468
-------- --------
Total operating expenses and taxes....................................... 363,467 369,655
-------- --------
OPERATING INCOME................................................................ 56,304 55,322
OTHER INCOME.................................................................... 4,741 5,241
-------- --------
..........
INCOME BEFORE NET INTEREST CHARGES.............................................. 61,045 60,563
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 40,640 46,995
Allowance for borrowed funds used during construction........................ (2,167) (749)
Other interest expense (credit).............................................. 31 (529)
Subsidiary's preferred dividend requirements................................. 2,250 2,150
-------- --------
Net interest charges..................................................... 40,754 47,867
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 20,291 12,696
Cumulative effect of accounting change (Net of income taxes of $30,168,000) (Note 5) 42,378 --
-------- --------
NET INCOME...................................................................... 62,669 12,696
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... (759) 8,256
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 63,428 $ 4,440
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these statements.
</FN>
52
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $4,114,337 $4,045,465
Less--Accumulated provision for depreciation.............................. 1,834,329 1,824,884
---------- ----------
2,280,008 2,220,581
---------- ----------
Construction work in progress-
Electric plant.......................................................... 164,966 153,104
Nuclear fuel............................................................ 44,406 45,354
---------- ----------
209,372 198,458
---------- ----------
2,489,380 2,419,039
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 416,836 435,907
Nuclear plant decommissioning trusts...................................... 234,855 230,527
Long-term notes receivable from associated companies...................... 102,860 102,978
Other..................................................................... 20,914 21,004
---------- ----------
775,465 790,416
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 826 30,382
Receivables-
Customers............................................................... 14,184 11,317
Associated companies.................................................... 63,946 74,002
Other (less accumulated provisions of $1,015,000 for uncollectible
accounts at both dates)............................................... 126,322 134,375
Notes receivable from associated companies................................ 565 447
Materials and supplies, at average cost-
Owned................................................................... 18,356 18,293
Under consignment....................................................... 38,159 38,094
Prepayments and other..................................................... 2,445 4,217
---------- ----------
264,803 311,127
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 943,331 939,804
Goodwill.................................................................. 1,370,639 1,370,639
Property taxes............................................................ 79,430 79,430
Other..................................................................... 25,065 24,798
---------- ----------
2,418,465 2,414,671
---------- ----------
$5,948,113 $5,935,253
========== ==========
53
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
---------- ------------
(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 $ 981,962
Accumulated other comprehensive loss.................................... (46,585) (44,051)
Retained earnings....................................................... 352,173 288,721
---------- ----------
Total common stockholder's equity................................... 1,287,550 1,226,632
Preferred stock-
Not subject to mandatory redemption..................................... 96,404 96,404
Subject to mandatory redemption......................................... 5,019 5,021
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000
Long-term debt............................................................ 1,972,400 1,975,001
---------- ----------
3,461,373 3,403,058
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 343,199 388,190
Accounts payable-
Associated companies.................................................... 229,544 267,664
Other................................................................... 8,574 14,583
Notes payable to associated companies..................................... 321,828 288,583
Accrued taxes............................................................. 129,158 126,262
Accrued interest.......................................................... 60,611 51,767
Other..................................................................... 35,694 64,324
---------- ----------
1,128,608 1,201,373
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 692,278 659,044
Accumulated deferred investment tax credits............................... 71,160 72,125
Nuclear plant decommissioning costs....................................... -- 239,720
Asset retirement obligation............................................... 242,208 --
Retirement benefits....................................................... 173,765 171,968
Other..................................................................... 178,721 187,965
---------- ----------
1,358,132 1,330,822
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$5,948,113 $5,935,253
========== ==========
<FN>
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these balance sheets.
</FN>
54
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2003 2002
-------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 62,669 $ 12,696
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization.............................. 26,557 28,471
Nuclear fuel and lease amortization...................................... 5,044 5,990
Other amortization....................................................... (4,613) (3,892)
Deferred income taxes, net............................................... 35,474 7,196
Investment tax credits, net.............................................. (965) (902)
Receivables.............................................................. 15,242 6,816
Materials and supplies................................................... (128) (1,366)
Accounts payable......................................................... (44,129) 18,322
Cumulative effect of accounting change................................... (72,547) --
Accrued taxes............................................................ 2,896 (5,068)
Accrued interest......................................................... 8,844 5,569
Prepayments and other.................................................... 1,772 22,508
Deferred rents and sale/leaseback........................................ (26,603) 14,877
Other.................................................................... (4,693) (23,695)
-------- ---------
Net cash provided from operating activities............................ 4,820 87,522
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net................................................. 33,245 75,484
Redemptions and Repayments-
Preferred Stock............................................................ -- (100,000)
Long-term debt............................................................. (45,103) (94)
Dividend Payments-
Preferred stock............................................................ (1,865) (5,252)
-------- ---------
Net cash provided from (used for) financing activities................. (13,723) (29,862)
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (31,218) (36,470)
Capital trust investments.................................................... 19,071 --
Other........................................................................ (8,506) (6,224)
-------- ---------
Net cash provided from (used for) investing activities................. (20,653) (42,694)
-------- ---------
Net increase (decrease) in cash and cash equivalents............................ (29,556) 14,966
Cash and cash equivalents at beginning of period ............................... 30,382 296
-------- ---------
Cash and cash equivalents at end of period...................................... $ 826 $ 15,262
======== =========
<FN>
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these statements.
</FN>
55
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of
Directors 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 March 31, 2003, and the
related consolidated statements of income and cash flows for the three-month
periods ended March 31, 2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
56
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
CEI is a wholly owned, electric utility subsidiary of FirstEnergy.
CEI conducts business in portions of Ohio, providing regulated electric
distribution services. CEI also provides generation services to those customers
electing to retain them as their power supplier. CEI provides power directly to
alternative energy suppliers under CEI's transition plan. CEI has unbundled 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
- ---------------------
Earnings on common stock in the first quarter of 2003 increased to
$63.4 million from $4.4 million in the first quarter of 2002. Earnings on common
stock in the first quarter of 2003 included an after-tax credit of $42.4 million
from the cumulative effect of an accounting change due to the adoption of SFAS
143, "Accounting for Asset Retirement Obligations." Income before the cumulative
effect was $20.3 million in the first quarter of 2003, compared to $12.7 million
for the same period of 2002.
Operating revenues decreased by $5.2 million or 1.2% in the first
quarter of 2003 from the same period in 2002. The lower revenues resulted from
reduced kilowatt-hour sales, which were partially offset by the effects of
colder weather on distribution deliveries to residential and commercial
customers. Kilowatt-hour sales to retail customers declined by 4.3% in the first
quarter of 2003 from the same quarter of 2002, which reduced generation sales
revenue by $6.6 million. Electric generation services provided by alternative
suppliers as a percent of total sales deliveries in CEI's franchise area
increased to 37.6% in the first quarter of 2003 from 28.5% in the first quarter
of 2002.
Distribution deliveries increased 10.5% in the first quarter of 2003
compared to the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). As a result, revenues from
electricity throughput increased by $15.5 million in the first quarter of 2003
from the same quarter of the prior year. The increase reflected higher volumes,
offset in part by lower unit prices. Distribution deliveries to residential and
commercial customers benefited from colder than normal weather, while a
substantial increase in distribution deliveries to industrial customers, despite
the continued effect of a sluggish economy, resulted from an expansion of steel
production in the franchise area.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues -- $5.8
million in the first quarter of 2003 compared with the corresponding period of
2002. These revenue reductions are deferred for future recovery under CEI's
transition plan and do not materially affect current period earnings.
Sales revenues from wholesale customers decreased by $10.7 million
(primarily to FES) in the first quarter of 2003 compared with the first quarter
of 2002, due to reduced nuclear generation from the extended outage of the
Davis-Besse Plant (see Davis-Besse Restoration).
57
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the first quarter of 2002 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
----------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. (4.3)%
Wholesale............................... (17.8)%
- ----------------------------------------------------------------------
Total Electric Generation Sales........... (11.3)%
====================================================
Distribution Deliveries:
Residential............................. 12.9%
Commercial.............................. 7.0%
Industrial.............................. 10.9%
- ----------------------------------------------------------------------
Total Distribution Deliveries............. 10.5%
====================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $6.2 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $(4.6)
Purchased power costs............................ (3.1)
Nuclear operating costs.......................... (8.3)
Other operating costs............................ 9.0
--------------------------------------------------------------
Total operation and maintenance expenses....... (7.0)
Provision for depreciation and amortization...... (1.9)
General taxes.................................... 1.0
Income taxes..................................... 1.7
--------------------------------------------------------------
Total operating expenses and taxes............. $(6.2)
===============================================================
Lower fuel costs in the first quarter of 2003, compared with the
first quarter of 2002 resulted from reduced nuclear generation (down 21%). The
lower purchased power costs reflected reduced unit costs offset in part by
additional kilowatt-hours purchased. Two scheduled refueling outages in the
first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of
refueling outages in the first quarter of 2003 more than offset incremental
costs associated with the extended outage of Davis-Besse, producing the lower
nuclear operating costs. The increase in other operating costs resulted in part
from higher employee benefit costs.
The decrease in depreciation and amortization charges in the first
quarter of 2003, compared with the first quarter of 2002 was attributable to
several factors - higher shopping incentive deferrals ($5.8 million) and lower
charges resulting from the implementation of SFAS 143 ($3.0 million), including
revised service life assumptions for generating plants ($4.0 million). Partially
offsetting these decreases were increased amortization of regulatory assets
being recovered under CEI's transition plan ($3.6 million) and recognition of
depreciation on three fossil plants ($8.1 million), which had been held pending
sale in the first quarter of 2002 but were subsequently retained by FirstEnergy
in the fourth quarter of 2002.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $7.1
million in the first quarter of 2003 from the same quarter last year, reflecting
redemptions and refinancings since the end of the first quarter of 2002. CEI's
net debt redemptions totaled $15.0 million during the first quarter of 2003
which will result in annualized savings of $1.2 million.
Cumulative Effect of Accounting Changes
Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded
an after-tax credit to net income of $42.4 million. CEI identified applicable
legal obligations as defined under the new accounting standard for nuclear power
plant decommissioning, reclamation of a sludge disposal pond at the Bruce
Mansfield Plant, and closure of two coal ash disposal sites. As a result of
adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were
recorded as part of the carrying amount of the related long-lived asset, offset
by accumulated depreciation of $6.8 million. The
58
asset retirement obligation liability at the date of adoption was $238.3
million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, CEI had
recorded decommissioning liabilities of $239.7 million, including unrealized
gains on the decommissioning trust funds of $0.4 million. The cumulative effect
adjustment for unrecognized depreciation, accretion offset by the reduction in
the existing decommissioning liabilities and ceasing the accounting practice of
depreciating non-regulated generation assets using a cost of removal component
was a $72.5 million increase to income, or $42.4 million net of income taxes.
Unrealized gains on decommissioning trust investments ($0.2 million net of tax)
formerly included in the decommissioning liability balances as of December 31,
2002 were offset against OCI upon adoption of SFAS 143 (see Note 5).
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $9.0 million in the
first quarter of 2003, compared to the same period last year, principally due to
optional redemptions of preferred stock in 2002.
Capital Resources and Liquidity
- -------------------------------
CEI's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
CEI expects to meet its contractual obligations with cash from operations.
Thereafter, CEI expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, CEI had $0.8 million of cash and cash
equivalents, compared with $30.4 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter
of 2003, compared with the first quarter of 2002 were as follows:
Operating Cash Flows 2003 2002
-----------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 52 $50
Working capital and other............ (47) 38
-----------------------------------------------------------
Total................................ $ 5 $88
===========================================================
(1) Includes net income, depreciation and
amortization, deferred income taxes, investment
tax credits and major noncash charges.
Net cash provided from operating activities decreased $83 million due
to an $85 million increase in working capital - that decrease was offset in part
by a $2 million increase in cash earnings. The largest factors contributing to
the increase in working capital and other were lower accounts payable from
associated companies in the first quarter of 2003 compared with corresponding
amounts in the first quarter of 2002 ($68 million).
Cash Flows From Financing Activities
Net cash used for financing activities declined $16 million in the
first quarter of 2003 from the first quarter of 2002. The decrease in funds used
for financing activities primarily reflected lower security redemptions and
repayments, which were partially offset by a net reduction in short-term
borrowings.
CEI had about $1.4 million of cash and temporary investments and
approximately $321.8 million of short-term indebtedness as of March 31, 2003.
CEI had the capability to issue $545.5 million of additional first mortgage
bonds on the basis of property additions and retired bonds. CEI has no
restrictions on the issuance of preferred stock.
Cash Flows From Investing Activities
Net cash used for investing activities decreased $22 million in the
first quarter of 2003 from the same quarter of 2002 due to a reduction in the
Shippingport Capital Trust investment and lower capital expenditures.
59
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $85 million,
including $9 million for nuclear fuel. CEI has additional requirements of
approximately $101 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including CEI.
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including CEI. Moody's noted that merger debt had put pressure on
FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all
levels within the company although those plans had been delayed by external
events.
Other Obligations
Obligations not included on CEI's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving the Bruce
Mansfield Plant. As of March 31, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $157
million. CEI sells substantially all of its retail customer receivables, which
provided $96 million of off-balance sheet financing as of March 31, 2003.
Equity Price Risk
- -----------------
Included in CEI's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $117
million and $119 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $12 million reduction in fair value as of March 31, 2003.
Outlook
- -------
Beginning in 2001, CEI's customers were able to select alternative
energy suppliers. CEI continues to deliver power to residential homes and
businesses through its existing distribution systems, which remain regulated.
Customer rates have been restructured into separate components to support
customer choice. In Ohio CEI has a continuing responsibility to provide power to
those customers not choosing to receive power from an alternative energy
supplier subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of CEI's customers elects to obtain power
from an alternative supplier, CEI reduces the customer's bill with a "generation
shopping credit," based on the regulated generation component (plus an
incentive), and the customer receives a generation charge from the alternative
supplier. CEI has continuing PLR responsibility to its franchise customers
through December 31, 2005.
Regulatory assets are costs which have been authorized by the PUCO
and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. Regulatory assets increased $3.5 million to $943.3 million
as of March 31, 2003 from the balance as of December 31, 2002. All of CEI's
regulatory assets are expected to continue to be recovered under the provisions
of its transition plan.
60
As part of CEI's Ohio transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. CEI is also
required to provide 400 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. CEI's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated
a formal inspection process at the Davis-Besse nuclear plant. This action was
taken in response to corrosion found by FENOC in the reactor vessel head near
the nozzle penetration hole during a refueling outage in the first quarter of
2002. The purpose of the formal inspection process is to establish criteria for
NRC oversight of the licensee's performance and to provide a record of the major
regulatory and licensee actions taken, and technical issues resolved, leading to
the NRC's approval of restart of the plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the first half of the summer of 2003. The NRC must authorize restart
of the plant following its formal inspection process before the unit can be
returned to service. While the additional maintenance work has delayed
FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments
in the unit's future safety, reliability and performance to be essential.
Significant delays in Davis-Besse's return to service, which depends on the
successful resolution of the management and technical issues as well as NRC
approval, could trigger an evaluation for impairment of the nuclear plant (see
Significant Accounting Policies below).
Incremental expenses associated with the extended Davis-Besse outage
in the first quarter of 2003 totaled $88.6 million, including $36.3 million for
maintenance work and $52.3 million for fuel and purchased power. CEI's ownership
share is 51.38% of those expenses. It is anticipated that an additional $13.7
million in maintenance costs will be spent during the remainder of the
Davis-Besse outage. Replacement power costs are expected to be $15 million per
month in the non-summer months and $20-25 million per month during the summer.
Environmental Matters
CEI believes it is in compliance with the current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from its
generating facilities. Various regulatory and judicial actions have since sought
to further define NOx reduction requirements (see Note 2 - Environmental
Matters). CEI continues to evaluate its compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. CEI cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
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.
CEI 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.
61
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of March 31, 2003, 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's total accrued
liabilities were approximately $2.5 million as of March 31, 2003.
The effects of compliance on CEI with regard to environmental matters
could have a material adverse effect on its earnings and competitive position.
These environmental regulations affect its earnings and competitive position to
the extent CEI competes with companies that are not subject to such regulations
and therefore do not bear the risk of costs associated with compliance, or
failure to comply, with such regulations. CEI believes it is in material
compliance with existing regulations, but is unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
Legal Matters
Various lawsuits, claims and proceedings related to CEI's normal
business operations are pending against CEI, the most significant of which are
described above.
Significant Accounting Policies
- -------------------------------
CEI 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 CEI's financial results. All of CEI'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 those 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 its customers based on the costs that the 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. As of March 31, 2003, CEI's regulatory
assets totaled $943.3 million. 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 been
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 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
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these
62
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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 2002 and
2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension
costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As
of December 31, 2002 the assumed return on plan assets was reduced to 9.00%
based upon FirstEnergy's projection of future returns and pension trust
investment allocation of approximately 60% large cap equities, 10% small cap
equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing
to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy
included the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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 asset 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).
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, CEI
evaluates its goodwill for impairment at least annually and would make such an
evaluation more frequently if indicators of impairment should arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value including goodwill, an impairment for goodwill
must be recognized in the financial statements. If impairment were to occur CEI
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.
CEI's annual review was completed in the third quarter of 2002. The results of
that review indicated no impairment of goodwill. The forecasts used in CEI's
evaluations of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on its future evaluations of goodwill. As of March 31, 2003, CEI had
approximately $1.4 billion of goodwill.
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (CEI's third
63
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
CEI currently has transactions which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. CEI currently consolidates the majority of these
entities and believes it will continue to consolidate following the adoption of
FIN 46. One of these entities CEI is currently consolidating is the Shippingport
Capital Trust which reacquired a portion of the off-balance sheet debt issued in
connection with the sale and leaseback of its interest in the Bruce Mansfield
Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated
parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., an
affiliated company.
64
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2003 2002
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $231,822 $244,167
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 7,681 11,391
Purchased power.............................................................. 74,251 82,404
Nuclear operating costs...................................................... 65,980 75,098
Other operating costs........................................................ 39,592 34,879
-------- --------
Total operation and maintenance expenses................................. 187,504 203,772
Provision for depreciation and amortization.................................. 20,240 21,368
General taxes................................................................ 15,008 13,748
Income taxes (benefit)....................................................... (1,557) (4,379)
-------- --------
Total operating expenses and taxes....................................... 221,195 234,509
-------- --------
OPERATING INCOME................................................................ 10,627 9,658
OTHER INCOME.................................................................... 3,100 4,343
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 13,727 14,001
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 11,815 15,872
Allowance for borrowed funds used during construction........................ (1,306) (428)
Other interest expense (credit).............................................. 168 (735)
-------- --------
Net interest charges..................................................... 10,677 14,709
-------- --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 3,050 (708)
Cumulative effect of accounting change (net of income taxes of
$18,201,000) (Note 5) ........................................................ 25,550 --
-------- --------
NET INCOME (LOSS)............................................................... 28,600 (708)
-------- --------
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 1,605 4,724
-------- --------
EARNINGS (LOSSES) ATTRIBUTABLE TO COMMON STOCK.................................. $ 26,995 $ (5,432)
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these statements.
</FN>
65
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
---------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,655,389 $1,600,860
Less--Accumulated provision for depreciation.............................. 723,821 706,772
---------- ----------
931,568 894,088
---------- ----------
Construction work in progress-
Electric plant.......................................................... 110,267 104,091
Nuclear fuel............................................................ 30,464 33,650
---------- ----------
140,731 137,741
---------- ----------
1,072,299 1,031,829
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 223,335 240,963
Nuclear plant decommissioning trusts...................................... 179,511 174,514
Long-term notes receivable from associated companies...................... 162,109 162,159
Other..................................................................... 2,172 2,236
---------- ----------
567,127 579,872
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 1,445 20,688
Receivables-
Customers............................................................... 5,640 4,711
Associated companies.................................................... 44,275 55,245
Other................................................................... 4,570 6,778
Notes receivable from associated companies................................ 6,452 1,957
Materials and supplies, at average cost-
Owned................................................................... 13,768 13,631
Under consignment....................................................... 23,587 22,997
Prepayments and other..................................................... 8,576 3,455
---------- ----------
108,313 129,462
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 387,130 392,643
Goodwill.................................................................. 445,732 445,732
Property taxes............................................................ 23,429 23,429
Other..................................................................... 14,641 14,257
---------- ----------
870,932 876,061
---------- ----------
$2,618,671 $2,617,224
========== ==========
66
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
---------- ------------
(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................................................... 428,559 428,559
Accumulated other comprehensive loss.................................... (21,638) (21,115)
Retained earnings....................................................... 136,812 109,817
---------- ----------
Total common stockholder's equity................................... 739,403 712,931
Preferred stock not subject to mandatory redemption....................... 126,000 126,000
Long-term debt............................................................ 556,080 557,265
---------- ----------
1,421,483 1,396,196
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 115,755 189,355
Accounts payable-
Associated companies.................................................... 120,483 171,862
Other................................................................... 6,100 8,638
Notes payable to associated companies..................................... 248,045 149,653
Accrued taxes............................................................. 40,712 34,967
Accrued interest.......................................................... 14,978 16,377
Other..................................................................... 52,416 57,232
---------- ----------
598,489 628,084
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 246,517 223,087
Accumulated deferred investment tax credits............................... 28,993 29,491
Nuclear plant decommissioning costs....................................... -- 180,856
Asset retirement obligation............................................... 174,877 --
Retirement benefits....................................................... 83,324 82,553
Other..................................................................... 64,988 76,957
---------- ----------
598,699 592,944
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 2).......................................
---------- ----------
$2,618,671 $2,617,224
========== ==========
<FN>
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these balance sheets.
</FN>
67
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
--------------------------
2003 2002
-------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)............................................................... $ 28,600 $ (708)
Adjustments to reconcile net income (loss) to net
cash from operating activities-
Provision for depreciation and amortization.............................. 20,240 21,368
Nuclear fuel and lease amortization...................................... 2,768 3,573
Deferred income taxes, net............................................... 22,675 5,314
Investment tax credits, net.............................................. (498) (486)
Receivables.............................................................. 12,249 20,022
Materials and supplies................................................... (727) (651)
Accounts payable......................................................... (53,917) 2,861
Cumulative effect of accounting change................................... (43,751) --
Accrued taxes............................................................ 5,745 (5,710)
Accrued interest......................................................... (1,399) (2,030)
Prepayments and other.................................................... (5,121) 9,987
Deferred rents and sale/leaseback........................................ (1,522) 24,878
Other.................................................................... (15,293) (12,653)
-------- --------
Net cash provided from (used for) operating activities................. (29,951) 65,765
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net................................................. 98,392 68,998
Redemptions and Repayments-
Preferred stock............................................................ -- (85,299)
Long-term debt............................................................. (73,600) (94)
Dividend Payments-
Common stock............................................................... -- (5,600)
Preferred stock............................................................ (2,211) (3,425)
-------- --------
Net cash provided from (used for) financing activities................. 22,581 (25,420)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (17,242) (25,559)
Loans to associated companies................................................ (4,445) (6,301)
Capital trust investments.................................................... 17,628 (57)
Other........................................................................ (7,814) (6,121)
-------- --------
Net cash provided from (used for) investing activities................. (11,873) (38,038)
-------- --------
Net increase (decrease) in cash and cash equivalents............................ (19,243) 2,307
Cash and cash equivalents at beginning of period................................ 20,688 302
-------- --------
Cash and cash equivalents at end of period...................................... $ 1,445 $ 2,609
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these statements.
</FN>
68
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors of The Toledo
Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo
Edison Company and its subsidiary as of March 31, 2003, and the related
consolidated statements of income and cash flows for the three-month periods
ended March 31, 2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
69
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE
conducts business in portions of Ohio, providing regulated electric distribution
services. TE also provides generation services to those customers electing to
retain them as their power supplier. TE provides power directly to wholesale
customers under previously negotiated contracts, as well as to alternative
energy suppliers under TE's transition plan. TE has unbundled 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
Earnings on common stock in the first quarter of 2003 increased to
$27.0 million from a loss of $5.4 million in the first quarter of 2002. Earnings
on common stock in the first quarter of 2003 included an after-tax credit of
$25.6 million from the cumulative effect of an accounting change due to the
adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income
before the cumulative effect was $3.1 million in the first quarter of 2003,
compared to a net loss of $0.7 million for the same period of 2002. Improved
results in the first quarter of 2003 reflected reduced financing costs and lower
operating expenses. Substantially offsetting these improvements were lower
operating revenues from reduced kilowatt-hour sales.
Operating revenues decreased by $12.3 million or 5.1% in the first
quarter of 2003 from the same period in 2002. The lower revenues resulted from
reduced kilowatt-hour sales which were partially offset by the effects of colder
weather on distribution deliveries to residential and commercial customers.
Kilowatt-hour sales to retail customers declined by 3.5% in the first quarter of
2003 from the same quarter of 2002, which reduced generation sales revenue by
$11.6 million. Electric generation services provided by alternative suppliers as
a percent of total sales deliveries in TE's franchise area increased to 21.8% in
the first quarter of 2003 from 14.4% in the first quarter of 2002.
Distribution deliveries increased 5.8% in the first quarter of 2003
compared to the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). As a result, revenues from
electricity throughput increased by $20.7 million in the first quarter of 2003
from the first quarter of 2002. The increase reflected higher unit prices, which
accounted for two-thirds of the increase and higher volumes. Distribution
deliveries benefited from substantially higher residential and commercial
demand, due in larger part to colder than normal weather, that was moderated by
the continued effect of a sluggish economy and its impact on demand by
industrial customers in TE's franchise area.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues by $2.2
million in the first quarter of 2003 compared with the same period last year.
These revenue reductions are deferred for future recovery under TE's transition
plan and do not materially affect current period earnings.
Sales revenues from wholesale customers decreased by $21.0 million
(primarily to FES) in the first quarter of 2003 compared with the first quarter
of 2002, due to reduced nuclear generation from the extended outage of the
Davis-Besse Plant (see Davis-Besse Restoration).
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the first quarter of 2002 are summarized in the
following table:
70
Changes in Kilowatt-Hour Sales
----------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (3.5)%
Wholesale............................. (28.1)%
- ----------------------------------------------------------------------
Total Electric Generation Sales........... (15.2)%
====================================================
Distribution Deliveries:
Residential........................... 10.9%
Commercial............................ 11.7%
Industrial............................ 0.3%
- ---------------------------------------------------------------------
Total Distribution Deliveries............. 5.8%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $13.3 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ (3.7)
Purchased power costs............................ (8.2)
Nuclear operating costs.......................... (9.1)
Other operating costs............................ 4.7
--------------------------------------------------------------
Total operation and maintenance expenses....... (16.3)
Provision for depreciation and amortization...... (1.1)
General taxes.................................... 1.3
Income taxes..................................... 2.8
--------------------------------------------------------------
Total operating expenses and taxes............. $(13.3)
===============================================================
Lower fuel costs in the first quarter of 2003, compared with the same
quarter of 2002, resulted from reduced nuclear generation (down 30%). The lower
purchased power costs reflected fewer kilowatt-hours required for customer
needs. Two scheduled refueling outages in the first quarter of 2002 (Beaver
Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first
quarter of 2003 more than offset incremental costs associated with the extended
outage of Davis-Besse, producing the lower nuclear operating costs. The increase
in other operating costs resulted in part from higher employee benefit costs.
Charges for depreciation and amortization decreased slightly in the
first quarter of 2003 compared with the first quarter of 2002, was attributable
to several factors - higher shopping incentive deferrals ($2.2 million) and
lower charges resulting from the implementation of SFAS 143 ($4.0 million),
including revised service life assumptions for generating plants ($3.0 million).
Nearly offsetting these decreases were increased amortization of regulatory
assets being recovered under TE's transition plan ($5.3 million) and recognition
of depreciation on the Bay Shore generating plant ($1.5 million), which had been
held pending sale in the first quarter of 2002 but was subsequently retained by
FirstEnergy in the fourth quarter of 2002.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $4.0
million in the first quarter of 2003 from the same period last year, reflecting
security redemptions and refinancings since the end of the first quarter of
2002. TE's net debt redemptions totaled $53.4 million during the first quarter
of 2003, which will result in annualized savings of $4.2 million.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded
an after-tax credit to net income of $25.6 million. TE identified applicable
legal obligations as defined under the new accounting standard for nuclear power
plant decommissioning and reclamation of a sludge disposal pond at the Bruce
Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $41.1 million were recorded as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $5.5
million. The asset retirement obligation liability at the date of adoption was
$172 million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, TE had
recorded decommissioning liabilities of $180.8 million, including
71
unrealized gains on the decommissioning trust funds of $1.9 million. The
cumulative effect adjustment for unrecognized depreciation, accretion offset by
the reduction in the existing decommissioning liabilities and ceasing the
accounting practice of depreciating non-regulated generation assets using a cost
of removal component was a $43.8 million increase to income, or $25.6 million
net of income taxes. Unrealized gains on decommissioning trust investments ($1.1
million net of tax) formerly included in the decommissioning liability balances
as of December 31, 2002 were offset against OCI upon the adoption of SFAS 143
(see Note 5).
Capital Resources and Liquidity
- -------------------------------
TE's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
TE expects to meet its contractual obligations with cash from operations.
Thereafter, TE expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, TE had $1.4 million of cash and cash
equivalents, compared with $20.7 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided by (used for) operating activities during the first
quarter of 2003, compared with the corresponding period in 2002 were as follows:
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 30 $29
Working capital and other............ (60) 37
-------------------------------------------------------------
Total................................ $(30) $66
=============================================================
(1) Includes net income, depreciation and
amortization, deferred income taxes, investment
tax credits and major noncash charges.
Net cash used for operating activities was $30 million in the first
quarter of 2003, a $96 million change from the $66 million provided by operating
activities in the first quarter of 2002. The decrease in funds from operating
activities resulted from a $97 million increase in working capital - principally
reduced accounts payable (primarily to associated companies) which contributed
$56.8 million to the increase in working capital requirements.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash provided from financing
activities increased to $23 million from net cash used for financing of $25
million in the first quarter of 2002. The increase in cash provided from
financing activities primarily resulted from additional short-term borrowings
from associated companies and a slight reduction in security redemptions and
repayments.
TE had approximately $7.9 million of cash and temporary investments
and approximately $248 million of short-term indebtedness as of March 31, 2003.
TE is currently precluded from issuing first mortgage bonds or preferred stock
based upon applicable earnings coverage tests as of March 31, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities decreased $26 million between
the first quarter of 2003 and the same quarter of 2002 due to reduced capital
expenditures and a reduction in the Shippingport Capital Trust investment.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $52 million,
including $9 million for nuclear fuel. TE has additional requirements of
approximately $43 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
72
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including TE.
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including TE. Moody's noted that merger debt had put pressure on
FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all
levels within the company although those plans had been delayed by external
events.
Other Obligations
Obligations not included on TE's Consolidated Balance Sheet primarily
consist of sale and leaseback arrangements involving the Bruce Mansfield Plant
and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale
and leaseback operating lease commitments, net of trust investments, totaled
$509 million. TE sells substantially all of its retail customer receivables,
which provided $49 million of off-balance sheet financing as of March 31, 2003.
Equity Price Risk
- -----------------
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $90
million as of March 31, 2003 and December 31, 2002. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $9 million
reduction in fair value as of March 31, 2003.
Outlook
- -------
Beginning in 2001, TE's customers were able to select alternative
energy suppliers. TE continues to deliver power to residential homes and
businesses through its existing distribution system, which remains regulated.
Customer rates have been restructured into separate components to support
customer choice. TE has a continuing responsibility to provide power to those
customers not choosing to receive power from an alternative energy supplier
subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of TE's Ohio customers elects to obtain
power from an alternative supplier, TE reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive), and the customer receives a generation charge from the
alternative supplier. TE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
Regulatory assets are costs which have been authorized by The Public
Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission
for recovery from customers in future periods and, without such authorization,
would have been charged to income when incurred. Regulatory assets declined $5.5
million to $387.1 million as of March 31, 2003 from the balance as of December
31, 2002, resulting from recovery of transition plan regulatory assets.
As part of TE's transition plan it is obligated to supply electricity
to customers who do not choose an alternative supplier. TE is also required to
provided 160 megawatts (MW) of low cost supply to unaffiliated alternative
suppliers that serve customers within its service area. TE's competitive retail
sales affiliate, FES, acts as an alternate supplier for a portion of the load in
its franchise area.
73
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated
a formal inspection process at the Davis-Besse nuclear plant. This action was
taken in response to corrosion found by FENOC in the reactor vessel head near
the nozzle penetration hole during a refueling outage in the first quarter of
2002. The purpose of the formal inspection process is to establish criteria for
NRC oversight of the licensee's performance and to provide a record of the major
regulatory and licensee actions taken, and technical issues resolved, leading to
the NRC's approval of restart of the plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the first half of the summer of 2003 after completion of the
additional maintenance work and regulatory reviews. The NRC must authorize
restart of the plant following its formal inspection process before the unit can
be returned to service. While the additional maintenance work has delayed
FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments
in the unit's future safety, reliability and performance to be essential.
Significant delays in Davis-Besse's return to service, which depends on the
successful resolution of the management and technical issues as well as NRC
approval, could trigger an evaluation for impairment of the nuclear plant (see
Significant Accounting Policies below).
Incremental expenses associated with the extended Davis-Besse outage
in the first quarter of 2003 totaled $88.6 million, including $36.3 million for
maintenance work and $52.3 million for fuel and purchased power. TE's ownership
share is 48.62% of those expenses. It is anticipated that an additional $13.7
million in maintenance costs will be spent during the remainder of the
Davis-Besse outage. Replacement power costs are expected to be $15 million per
month in the non-summer months and $20-25 million per month during the summer.
Environmental Matters
TE believes it is in compliance with the current sulfur dioxide (SO2)
and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2C - Environmental
Matters). TE continues to evaluate its compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 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.
TE believes it is 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
74
eastern United States. State Implementation Plans (SIP) must comply by May 31,
2004 with individual state NOx budgets established by the EPA. Pennsylvania
submitted a SIP that requires compliance with the NOx budgets at the Companies'
Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires
compliance with the NOx budgets at the Companies' Ohio facilities by May 31,
2004.
TE 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 March 31, 2003, 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 total accrued
liabilities of approximately $0.2 million as of March 31, 2003.
The effects of compliance on TE with regard to environmental matters
could have a material adverse effect on its earnings and competitive position.
These environmental regulations affect its earnings and competitive position to
the extent TE competes with companies that are not subject to such regulations
and therefore do not bear the risk of costs associated with compliance, or
failure to comply, with such regulations. TE believes it is in material
compliance with existing regulations, but is unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
Legal Matters
Various lawsuits, claims and proceedings relayed to TE's normal
business operations are pending against TE, the most significant of which are
described above.
Significant Accounting Policies
- -------------------------------
TE 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 TE's financial results. All of TE'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 those 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 its customers based on the costs that the 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. As of March 31, 2003, TE's regulatory
assets totaled $387.1 million. 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 been 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 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
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
75
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.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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 asset 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).
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, TE evaluates
its goodwill for impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value including goodwill, an impairment for goodwill must be recognized
in the financial statements. If impairment were to occur, TE 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. TE's annual
review was completed in the third quarter of 2002. The results of that review
indicated no impairment of goodwill. The forecasts used in TE's annual review
was completed in the third quarter of 2002. The results of that review indicated
no impairment of goodwill. The forecasts used in TE's evaluations of goodwill
reflect operations consistent with its general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
its future evaluations of goodwill. As of March 31, 2003, TE had approximately
$446 million of goodwill.
Recently Issued Accounting Standard Not Yet Implemented
- -------------------------------------------------------
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (TE's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
76
TE currently has transactions which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. TE currently consolidates the majority of these
entities and believes it will continue to consolidate following the adoption of
FIN 46. One of these entities TE is currently consolidating is the Shippingport
Capital Trust, which reacquired a portion of the off-balance sheet debt issued
in connection with the sale and leaseback of its interest in the Bruce Mansfield
Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated
parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., a
majority owned subsidiary.
77
PENNSYLVANIA POWER COMPANY
STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2003 2002
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $128,343 $124,335
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 4,713 6,333
Purchased power.............................................................. 44,066 39,963
Nuclear operating costs...................................................... 46,929 22,332
Other operating costs........................................................ 16,550 9,952
-------- --------
Total operation and maintenance expenses................................. 112,258 78,580
Provision for depreciation and amortization.................................. 13,265 14,204
General taxes................................................................ 6,179 6,004
Income taxes (benefit)....................................................... (1,479) 10,416
-------- --------
Total operating expenses and taxes....................................... 130,223 109,204
-------- --------
OPERATING INCOME (LOSS)......................................................... (1,880) 15,131
OTHER INCOME.................................................................... 561 665
-------- --------
INCOME (LOSS) BEFORE NET INTEREST CHARGES....................................... (1,319) 15,796
-------- --------
NET INTEREST CHARGES:
Interest expense............................................................. 4,064 4,098
Allowance for borrowed funds used during construction........................ (629) (252)
-------- --------
Net interest charges..................................................... 3,435 3,846
-------- --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... (4,754) 11,950
Cumulative effect of accounting change (net of income taxes of
$7,532,000) (Note 5) 10,618 --
-------- --------
NET INCOME...................................................................... 5,864 11,950
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 912 926
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 4,952 $ 11,024
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these statements.
</FN>
78
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $761,120 $680,729
Less--Accumulated provision for depreciation.............................. 310,711 316,424
-------- --------
450,409 364,305
-------- --------
Construction work in progress-
Electric plant.......................................................... 58,232 44,696
Nuclear fuel............................................................ 22,071 8,812
-------- --------
80,303 53,508
-------- --------
530,712 417,813
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 119,270 119,401
Long-term notes receivable from associated companies...................... 38,823 38,921
Other..................................................................... 2,477 2,569
-------- --------
160,570 160,891
-------- --------
CURRENT ASSETS:
Cash and cash equivalents................................................. 1,827 1,222
Receivables-
Customers (less accumulated provisions of $719,000 and $702,000,
respectively, for uncollectible accounts)............................. 43,130 44,341
Associated companies.................................................... 29,364 42,652
Other................................................................... 2,499 5,262
Notes receivable from associated companies................................ 30,494 35,317
Materials and supplies, at average cost................................... 30,740 30,309
Prepayments............................................................... 21,634 5,346
-------- --------
159,688 164,449
-------- --------
DEFERRED CHARGES:
Regulatory assets......................................................... 77,776 156,903
Other..................................................................... 7,616 7,692
-------- --------
85,392 164,595
-------- --------
$936,362 $907,748
======== ========
79
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(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)
Accumulated other comprehensive loss.................................... (9,932) (9,932)
Retained earnings....................................................... 42,868 50,916
-------- --------
Total common stockholder's equity................................... 221,326 229,374
Preferred stock-
Not subject to mandatory redemption..................................... 39,105 39,105
Subject to mandatory redemption......................................... 13,500 13,500
Long-term debt............................................................ 171,508 185,499
-------- --------
445,439 467,478
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 80,539 66,556
Accounts payable-
Associated companies.................................................... 85,791 52,653
Other................................................................... 436 5,730
Accrued taxes............................................................. 16,778 12,507
Accrued interest.......................................................... 3,549 5,558
Other..................................................................... 9,865 10,479
-------- --------
196,958 153,483
-------- --------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 120,591 117,385
Accumulated deferred investment tax credits............................... 3,737 3,810
Asset retirement obligation............................................... 123,358 --
Nuclear plant decommissioning costs....................................... -- 119,863
Other..................................................................... 46,279 45,729
-------- --------
293,965 286,787
-------- --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
-------- --------
$936,362 $907,748
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these balance sheets.
</FN>
80
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
--------------------------
2003 2002
-------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 5,864 $ 11,950
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization................................ 13,265 14,204
Nuclear fuel and lease amortization........................................ 3,583 4,716
Deferred income taxes, net................................................. 6,122 (1,925)
Investment tax credits, net................................................ (620) (665)
Cumulative effect of accounting change (Note 5)............................ (18,150) --
Receivables................................................................ 17,262 (682)
Materials and supplies..................................................... (431) (572)
Accounts payable........................................................... 27,844 (15,759)
Accrued taxes.............................................................. 4,271 10,650
Accrued interest........................................................... (2,009) (1,638)
Prepayments and other...................................................... (16,288) (13,470)
Other...................................................................... (380) (274)
-------- --------
Net cash provided from operating activities............................ 40,333 6,535
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt............................................................. (16) (40,667)
Dividend Payments-
Common stock............................................................... (13,000) (7,800)
Preferred stock............................................................ (912) (926)
-------- --------
Net cash provided from (used for) financing activities................. (13,928) (49,393)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (31,054) (8,083)
Notes receivable from associated companies, net.............................. 4,921 53,063
Other........................................................................ 333 (1,188)
-------- --------
Net cash provided from (used for) investing activities................. (25,800) 43,792
-------- --------
Net increase (decrease) in cash and cash equivalents............................ 605 934
Cash and cash equivalents at beginning of period................................ 1,222 67
-------- --------
Cash and cash equivalents at end of period...................................... $ 1,827 $ 1,001
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these statements.
</FN>
81
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors of Pennsylvania
Power Company:
We have reviewed the accompanying balance sheet of Pennsylvania Power Company as
of March 31, 2003, and the related statements of income and cash flows for the
three-month periods ended March 31, 2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the balance sheet and the statement of
capitalization as of December 31, 2002, and the related statements of income,
common stockholder's equity, preferred stock, cash flows and taxes for the year
then ended (not presented herein), and in our report dated February 28, 2003 we
expressed an unqualified opinion on those financial statements. In our opinion,
the information set forth in the accompanying balance sheet as of December 31,
2002, is fairly stated in all material respects in relation to the balance sheet
from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
82
PENNSYLVANIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
Penn is a wholly owned, electric utility subsidiary of OE. Penn
conducts business in western Pennsylvania, providing regulated electric
distribution services. Penn also provides generation services to those customers
electing to retain it as their power supplier. Penn provides power directly to
wholesale customers under previously negotiated contracts. Penn has unbundled
the price of electricity into its component elements - including generation,
transmission, distribution and transition charges. Its power supply requirements
are provided by FES - an affiliated company.
Results of Operations
- ---------------------
Earnings on common stock in the first quarter of 2003 decreased to
$5.0 million from $11.0 million in the first quarter of 2002. Earnings on common
stock in the first quarter of 2003 included an after-tax credit of $10.6 million
from the cumulative effect of an accounting change due to the adoption of SFAS
143, "Accounting for Asset Retirement Obligations." The loss before the
cumulative effect was $4.8 million in the first three months of 2003, compared
to income of $12.0 million for the same period of 2002. The lower results in the
first quarter of 2003 reflected higher operating expenses -- primarily nuclear
operating costs, purchased power costs and employee benefit costs. These higher
costs were partially offset by additional revenues due to colder weather,
increased sales revenues to FES, lower fuel costs and reduced financing costs,
compared with the first quarter of 2002.
Operating revenues increased by $4.0 million or 3.2% in the first
quarter of 2003 compared with the same period in 2002. The higher revenues
resulted from increased distribution deliveries due to colder temperatures and
additional sales revenues to FES. Kilowatt-hour sales to retail customers were
higher by 7.7% in the first quarter of 2003 from the same quarter of 2002, which
increased generation sales revenue by $1.9 million. Electric generation services
provided by alternative suppliers as a percent of total sales delivered in
Penn's franchise area slightly increased by 0.9 percentage point in the first
quarter of 2003 from the first quarter of 2002.
Distribution deliveries increased 8.7% in the first quarter of 2003
compared with the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). This increased revenues from
electricity throughput by approximately $0.9 million in the first quarter of
2003 from the same quarter of the prior years.
Sales revenues from wholesale customers increased by $1.9 million
(primarily to FES) in the first quarter of 2003 compared to the same quarter of
2002, due to higher market prices. Increased wholesale revenues occurred despite
a reduction in kilowatt-hour sales in the first quarter of 2003 from the same
quarter last year, due to a 34.3% reduction in available nuclear generation from
Beaver Valley Unit 1 as a result of its refueling outage that began on March 8,
2003.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the same quarter of 2002 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
-----------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. 7.7%
Wholesale............................... (21.0)%
- ---------------------------------------------------------
Total Electric Generation Sales........... (9.5)%
====================================================
Distribution Deliveries:
Residential............................. 13.4%
Commercial.............................. 6.7%
Industrial.............................. 5.1%
- --------------------------------------------------------
Total Distribution Deliveries............. 8.7%
===================================================
83
Operating Expenses and Taxes
Total operating expenses and taxes increased by $21.0 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ (1.6)
Purchased power costs............................ 4.1
Nuclear operating costs.......................... 24.6
Other operating costs............................ 6.6
--------------------------------------------------------------
Total operation and maintenance expenses....... 33.7
Provision for depreciation and amortization...... (1.0)
General taxes.................................... 0.2
Income taxes..................................... (11.9)
--------------------------------------------------------------
Total operating expenses and taxes............. $ 21.0
==============================================================
Lower fuel costs in the first quarter of 2003, compared with the same
quarter of 2002, resulted from reduced nuclear generation. The increased
purchased power costs reflected additional kilowatt-hour purchases and higher
unit costs. Higher nuclear operating costs occurred in large part due to the
refueling outage at Beaver Valley Unit 1 (65.00% ownership) in the first quarter
of 2003 compared with refueling outage costs at Beaver Valley Unit 2 (13.74%
ownership) in the first quarter of 2002. The increase in other operating costs
reflects higher employee benefit costs and increased uncollectible customer
accounts.
Charges for depreciation and amortization decreased by $1.0 million
in the first quarter of 2003 compared to the first quarter of 2002 primarily
from lower charges resulting from the implementation of SFAS 143 ($0.3 million),
including revised service life assumptions for generating plants ($0.3 million).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
approximately $0.4 million in the first quarter of 2003 from the same period
last year, reflecting redemptions and refinancings since the first quarter of
2002.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, Penn recorded
an after-tax credit to net income of $10.6 million. Penn identified applicable
legal obligations as defined under the new standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs
of $78 million were recorded as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $9 million. The asset
retirement obligation (ARO) liability at the date of adoption was $121 million,
including accumulated accretion for the period from the date the liability was
incurred to the date of adoption. As of December 31, 2002, Penn had recorded
decommissioning liabilities of $120 million. Penn expects substantially all of
its nuclear decommissioning costs to be recoverable in rates over time.
Therefore, it recognized a regulatory liability of $69 million upon adoption of
SFAS 143 for the transition amounts related to establishing the ARO for nuclear
decommissioning for Penn. The remaining cumulative effect adjustment for
unrecognized depreciation accretion offset by the reduction in the liabilities
and ceasing the accounting practice of depreciating non-regulated generation
assets using a cost of removal component was a $18.2 million increase to income,
or $10.6 million net of income taxes (see Note 5).
Capital Resources and Liquidity
- -------------------------------
Penn's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
Penn expects to meet its contractual obligations with cash from operations.
Thereafter, Penn expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, Penn had $1.8 million of cash and cash
equivalents, compared with $1.2 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
84
Cash Flows From Operating Activities
Cash flows provided from operating activities during the first
quarter of 2003, compared with the corresponding period in 2002 were as follows:
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $10 $ 28
Working capital and other............ 30 (21)
-------------------------------------------------------------
Total................................ $40 $ 7
=============================================================
(1) Includes net income, depreciation and
amortization, deferred income taxes, investment
tax credits and major noncash charges.
Net cash from operating activities increased to $40 million in the
first quarter of 2003 from $7 million in the same period of 2002. The increase
in working capital and other primarily was due to a net change of $48 million
due to higher accounts payable from associated companies in the first quarter of
2003 compared with corresponding amounts in the first quarter of 2002. A
decrease in accounts receivable from associated companies also contributed $12
million to the increase in cash provided from working capital. The decrease in
cash earnings in the first quarter of 2003 compared with the first quarter of
2002 primarily resulted from higher nuclear operating costs.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash used for financing activities
decreased to $14 million from $49 million in the same period last year. The
decrease resulted from reduced long-term debt redemptions partially offset by
increased dividends to OE.
Penn had approximately $32.3 million of cash and temporary
investments and no short-term indebtedness as of March 31, 2003. Penn may borrow
from its affiliates on a short-term basis. Penn had the capability to issue $381
million of additional first mortgage bonds on the basis of property additions
and retired bonds. Based upon applicable earnings coverage tests, Penn could
issue up to $122 million of preferred stock (assuming no additional debt was
issued) as of March 31, 2003.
Cash Flows From Investing Activities
Net cash flows used for investing activities totaled $26 million in
the first quarter of 2003, compared to a net cash flows provided from investing
activities of $44 million for the same period of 2002. The $70 million change to
funds used for investing activities resulted from lower payments received on
notes from associated companies and additional capital expenditures.
In the first quarter of 2002, net cash flows provided from investing
activities totaled $44 million, principally from payments on the sale of
property to affiliates as part of corporate separation and the sale of
transmission facilities to ATSI, partially offset by property additions.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $41 million,
including $5 million for nuclear fuel. Penn has additional requirements of
approximately $42 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
85
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including Penn.
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including the OE Companies. Moody's noted that merger debt had put
pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt
at all levels within the company although those plans had been delayed by
external events.
Equity Price Risk
- -----------------
Included in Penn's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $43
million and $38 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $4 million reduction in fair value as of March 31, 2003.
Outlook
- -------
Beginning in 1999, Penn's customers were able to select alternative
energy suppliers and customer rates have been restructured into separate
components to support customer choice. Currently, a number of customers
previously electing to be served by alternative energy providers returned to the
Penn system for their energy needs. Penn has a continuing responsibility to
provide power to those customers not choosing to receive power from an
alternative energy supplier subject to certain limits. Adopting new approaches
to regulation and experiencing new forms of competition have created new
uncertainties. Penn continues to deliver power to residential homes and
businesses through its existing distribution system, which remains regulated.
Regulatory Matters
Regulatory assets are costs which have been authorized by the
Pennsylvania Public Utility Commission and the Federal Energy Regulatory
Commission, for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. Regulatory
assets declined $79.1 million to $77.8 million on March 31, 2003 from the
balance as of December 31, 2002, with $69.2 million of the decrease related to
the cumulative entry adopting SFAS 143. All of Penn's regulatory assets are
expected to continue to be recovered under the provisions of its regulatory
plan.
As part of Penn's transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. Penn's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area. In 2003, the total peak load
forecasted for customers electing to stay with Penn, including the load served
by Penn's affiliate is 955 megawatts.
Environmental Matters
Penn believes it is in compliance with the current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements. Penn continues to evaluate
its compliance plans and other compliance options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W.H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act (CAA). The civil complaint against OE and Penn
requests installation of "best available control technology" as well as civil
penalties of up to $27,500 per day. Although unable to predict the outcome of
these proceedings, OE and Penn believe the Sammis Plant is in full compliance
with the CAA and that the NOV and complaint are without merit. Penalties could
be imposed if the Sammis Plant continues to operate without correcting the
alleged violations and a court determines that the allegations are valid. The
Sammis Plant continues to operate while these proceedings are pending.
86
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.
Penn believes it is 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 its 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 Penn's
Pennsylvania facilities by May 1, 2003.
The effects of compliance on Penn with regard to environmental
matters could have a material adverse effect on its earnings and competitive
position. These environmental regulations affect Penn's earnings and competitive
position to the extent it competes with companies that are not subject to such
regulations and therefore do not bear the risk of costs associated with
compliance, or failure to comply, with such regulations. Penn believes it is in
material compliance with existing regulations, but are unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Significant Accounting Policies
- -------------------------------
Penn 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 Penn's financial results. All of the
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 those specific factors. Penn's more significant
accounting policies are described below.
Regulatory Accounting
Penn is subject to regulation that sets the prices (rates) they are
permitted to charge its customers based on the costs that the 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. As a
result of the changing regulatory framework in Pennsylvania, a significant
amount of regulatory assets have been recorded. As of March 31, 2003, Penn's
regulatory assets totaled $78 million. 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.
Revenue Recognition
Penn follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
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 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
87
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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 impairment other than of a
temporary nature has occurred, Penn recognizes a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
88
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2003 2002
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $656,952 $450,713
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 1,334 1,176
Purchased power.............................................................. 399,066 210,985
Other operating costs........................................................ 69,723 68,517
-------- --------
Total operation and maintenance expenses................................. 470,123 280,678
Provision for depreciation and amortization.................................. 60,167 63,903
General taxes................................................................ 15,812 17,003
Income taxes................................................................. 35,642 27,861
-------- --------
Total operating expenses and taxes....................................... 581,744 389,445
-------- --------
OPERATING INCOME................................................................ 75,208 61,268
OTHER INCOME.................................................................... 1,176 2,826
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 76,384 64,094
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 23,312 22,717
Allowance for borrowed funds used during construction........................ (123) (482)
Deferred interest............................................................ (3,202) 449
Other interest expense (credit).............................................. (159) (1,244)
Subsidiary's preferred stock dividend requirements........................... 2,674 2,675
-------- --------
Net interest charges..................................................... 22,502 24,115
-------- --------
NET INCOME...................................................................... 53,882 39,979
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 125 753
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 53,757 $ 39,226
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Jersey Central
Power & Light Company are an integral part of these statements.
</FN>
89
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
---------- ----------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $3,572,958 $3,478,803
Less--Accumulated provision for depreciation.............................. 1,454,468 1,343,846
---------- ----------
2,118,490 2,134,957
Construction work in progress - electric plant............................ 26,191 20,687
---------- ----------
2,144,681 2,155,644
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 106,390 106,820
Nuclear fuel disposal trust............................................... 155,403 149,738
Long-term notes receivable from associated companies...................... 20,333 20,333
Other..................................................................... 22,206 18,202
---------- ----------
304,332 295,093
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 1,836 4,823
Receivables-
Customers (less accumulated provisions of $4,620,000 and $4,509,000
respectively, for uncollectible accounts).............................. 228,123 247,624
Associated companies.................................................... 376 318
Other .................................................................. 19,789 20,134
Notes receivable from associated companies................................ 52,607 77,358
Materials and supplies, at average cost................................... 1,567 1,341
Prepayments and other..................................................... 21,675 37,719
---------- ----------
325,973 389,317
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 3,094,751 3,199,012
Goodwill.................................................................. 2,000,875 2,000,875
Other..................................................................... 15,644 12,814
---------- ----------
5,111,270 5,212,701
---------- ----------
$7,886,256 $8,052,755
========== ==========
90
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares -
15,371,270 shares outstanding......................................... $ 153,713 $ 153,713
Other paid-in capital................................................... 3,029,218 3,029,218
Accumulated other comprehensive loss.................................... (835) (865)
Retained earnings....................................................... 56,760 92,003
---------- ----------
Total common stockholder's equity................................... 3,238,856 3,274,069
Preferred stock not subject to mandatory redemption....................... 12,649 12,649
Company-obligated mandatorily redeemable preferred securities............. 125,243 125,244
Long-term debt............................................................ 1,204,713 1,210,446
---------- ----------
4,581,461 4,622,408
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 167,315 173,815
Accounts payable-
Associated companies.................................................... 107,880 170,803
Other................................................................... 79,249 106,504
Accrued taxes............................................................. 58,908 13,844
Accrued interest.......................................................... 32,932 27,161
Other..................................................................... 105,934 112,408
---------- ----------
552,218 604,535
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 707,995 691,721
Accumulated deferred investment tax credits............................... 9,364 9,939
Power purchase contract loss liability.................................... 1,637,650 1,710,968
Nuclear fuel disposal costs............................................... 166,692 166,191
Asset retirement obligation............................................... 105,390 --
Nuclear plant decommissioning costs....................................... 5,212 135,355
Other..................................................................... 125,486 111,638
---------- ----------
2,752,577 2,825,812
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$7,886,256 $8,052,755
========== ==========
<FN>
The preceding Notes to Financial Statements as they relate to Jersey Central
Power & Light Company are an integral part of these balance sheets.
</FN>
91
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2003 2002
-------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................................... $ 53,882 $ 39,979
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........................... 60,167 63,903
Other amortization.................................................... 185 511
Deferred costs, net................................................... (35,082) (65,608)
Deferred income taxes, net............................................ 14,977 8,678
Investment tax credits, net........................................... (575) (899)
Receivables........................................................... 19,788 44,122
Materials and supplies................................................ (226) 6
Accounts payable...................................................... (90,178) (4,966)
Prepayments and other................................................. 16,044 5,904
Accrued taxes......................................................... 45,064 34,570
Accrued interest...................................................... 5,771 4,353
Other................................................................. 6,034 1,837
-------- --------
Net cash provided from operating activities......................... 95,851 132,390
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments -
Long-term debt.......................................................... (10,090) (50,000)
Short-term borrowings, net.............................................. -- (18,149)
Dividend Payments-
Common stock............................................................ (89,000) --
Preferred stock......................................................... (125) (753)
-------- --------
Net cash provided from (used for) financing activities.............. (99,215) (68,902)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................ (24,323) (25,902)
Capital trust investments................................................. -- (101)
Notes receivable - associated companies, net.............................. 24,750 --
Other..................................................................... (50) (1,292)
-------- --------
Net cash provided from (used for) investing activities.............. 377 (27,295)
-------- --------
Net increase (decrease) in cash and cash equivalents......................... (2,987) 36,193
Cash and cash equivalents at beginning of period ............................ 4,823 31,424
-------- --------
Cash and cash equivalents at end of period................................... $ 1,836 $ 67,617
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Jersey Central
Power & Light Company are an integral part of these statements.
</FN>
92
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors 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 March 31, 2003, and the related
consolidated statements of income and cash flows for the three-month periods
ended March 31, 2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
93
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
JCP&L provides regulated transmission and distribution services in
northern, western and east central New Jersey. New Jersey customers are able to
choose their electricity suppliers as a result of legislation which restructured
the electric utility industry. JCP&L's regulatory plan required unbundling the
price for electricity into its component elements - including generation,
transmission, distribution and transition charges. Also under the regulatory
plan, JCP&L continues to deliver power to homes and businesses through its
existing distribution system and is required to maintain the "provider of last
resort" (PLR) obligation known as Basic Generation Services (BGS) for customers
who elect to retain JCP&L as their power supplier.
Results of Operations
- ---------------------
Earnings on common stock in the first quarter of 2003 increased to
$53.8 million from $39.2 million in the first quarter of 2002. Higher operating
revenues primarily due to increases in wholesale sales and distribution
deliveries were partially offset by higher purchased power costs.
Operating revenues increased by $206.2 million or 45.8% in the first
quarter of 2003 compared with the same period in 2002. The higher revenues
resulted from higher wholesale revenues that increased by $139.2 million over
the first quarter of 2002. JCP&L's BGS obligation was transferred to external
parties through a February 2002 auction process authorized by the New Jersey
Board of Public Utilities (NJBPU). The auction removed JCP&L's BGS obligation
for the period from August 1, 2002 through July 31, 2003, and as a result, it
has been selling all of its self-supplied energy (from non-utility generation
power contracts and owned generation) into the wholesale market. The NJBPU
subsequently approved the February 2003 BGS auction results for the period
beginning August 1, 2003.
Distribution deliveries increased 14.5% in the first quarter of 2003
from the corresponding quarter of 2002, increasing revenues from electricity
throughput by $37.4 million. Distribution deliveries benefited from
substantially higher residential and commercial demand, due in large part to
colder temperatures, which was partially offset by a decrease in industrial
demand. Changes in distribution deliveries in the first quarter of 2003 compared
with the first quarter of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Deliveries
------------------------------------------------------
Increase (Decrease)
Residential........................... 17.6%
Commercial............................ 18.1%
Industrial............................ (2.4)%
------------------------------------------------------
Total Distribution Deliveries........... 14.5%
=================================================
94
Operating Expenses and Taxes
Total operating expenses and taxes increased $192.3 million in the
first quarter of 2003 compared with the first quarter of 2002, primarily due to
increases in purchased power costs. The following table presents changes from
the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ 0.1
Purchased power costs............................ 188.1
Other operating costs............................ 1.2
--------------------------------------------------------------
Total operation and maintenance expenses....... 189.4
Provision for depreciation and amortization...... (3.7)
General taxes.................................... (1.2)
Income taxes..................................... 7.8
--------------------------------------------------------------
Total operating expenses and taxes............. $192.3
===============================================================
Higher purchased power costs in the first quarter of 2003, compared
to the same quarter of 2002, were due primarily to increased kilowatt-hour
purchases through two-party agreements and reduced deferred energy and capacity
costs. The decrease in depreciation and amortization charges of $3.7 million was
due to the cessation of amortization of regulatory assets related to the
previously divested Oyster Creek Nuclear Generating Station.
Net Interest Charges
Net interest charges decreased by $1.6 million in the first quarter
of 2003 compared with the first quarter of 2002, primarily due to debt
redemptions since the end of the first quarter of 2002. That decrease was
partially offset by interest on $320 million of transition bonds issued in June
2002 (see Note 1).
Capital Resources and Liquidity
- -------------------------------
JCP&L's cash requirements in 2003 for operating expenses,
construction expenditures and scheduled debt maturities are expected to be met
without increasing its net debt and preferred stock outstanding. Available
borrowing capacity under short-term credit facilities with affiliates will be
used to manage working capital requirements. Over the next three years, JCP&L
expects to meet its contractual obligations with cash from operations.
Thereafter, JCP&L expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, JCP&L had $1.8 million of cash and cash
equivalents, compared with $4.8 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from the first quarter of 2003 and 2002 operating
activities are as follows:
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $93 $ 46
Working capital and other............ 3 86
-------------------------------------------------------------
Total................................ $96 $132
=============================================================
(1) Includes net income, depreciation and
amortization, deferred costs recoverable as
regulatory assets, deferred income taxes and
investment tax credits.
Net cash from operating activities decreased to $96 million in the
first quarter of 2003 from $132 million in the first quarter of 2002. This
decrease was due to an $83 million increase in funds used for working capital
and other, partially offset by a $47 million increase in cash earnings. The
increase in working capital reflects a $85 million net decrease in accounts
payable. The cash earnings increase was partially attributable to increased
revenues from sales to the wholesale market in 2003.
95
Cash Flows From Financing Activities
In the first quarter of 2003, net cash used for financing activities
of $99 million primarily reflected the redemption of $10 million of secured
long-term debt and $89 million of common stock dividend payments to FirstEnergy.
In the first quarter of 2002, net cash used for financing activities totaled $69
million, primarily due to the redemption of debt.
As of March 31, 2003, JCP&L had approximately $54.4 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
(FMB) other than as collateral for senior notes, since its senior note
indentures prohibit (subject to certain exceptions) it from issuing any debt
which is senior to the senior notes. As of March 31, 2003. JCP&L had the
capability to issue $426 million of additional senior notes based upon FMB
collateral. Based upon applicable earnings coverage tests JCP&L could issue a
total of $1.55 billion of preferred stock (assuming no additional debt was
issued) as of March 31, 2003.
Cash Flows From Investing Activities
Net cash provided from investing activities totaled $0.4 million in
the first quarter of 2003, compared with net cash used of $27 million in the
first quarter of 2002. Net cash provided from investing in 2003 represented loan
repayments from associated companies offset by property additions. Net cash used
in investing activities in 2002 were principally for property additions.
During the last three quarters of 2003, capital requirements for
property additions are expected to be about $87 million. JCP&L has additional
requirements of approximately $164 million for maturing long-term debt during
the remainder of 2003. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including JCP&L.
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including JCP&L. Moody's noted that merger debt had put pressure on
FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all
levels within the company although those plans had been delayed by external
events.
Market Risk Information
- -----------------------
JCP&L uses various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price 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
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, it uses a variety of non-derivative and derivative instruments,
including forward contracts, options and future contracts. The derivatives are
used for hedging purposes. Most of JCP&L'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 the first quarter of 2003 is summarized in the
following table:
96
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
Non-Hedge Hedge Total
- ------------------------------------------------------------------------------------------------
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2003................... $ 8.7 $(0.1) $ 8.6
New contract value when entered............................... -- -- --
Additions/Increase in value of existing contracts............. 4.1 0.1 4.2
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. -- -- --
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2003 (1)... $12.8 $ -- $12.8
=================================================================================================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $ 0.1 $ 0.1
Regulatory Liability.......................................... $ 4.1 $ -- $ 4.1
<FN>
(1) Includes $12.8 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled contracts and
changes in techniques/assumptions.
</FN>
Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
Non-Hedge Hedge Total
---------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $ -- $ -- $ --
Non-Current-
Other Deferred Charges............ 12.8 -- 12.8
---------------------------------------------------------------------
Net assets........................ $12.8 $ -- $12.8
=====================================================================
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, 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 uses these results to develop
estimates of fair value for financial reporting purposes and for internal
management decision making. Sources of information for the valuation of
derivative contracts by year are summarized in the following table:
Source of Information
- - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(1) $ .3 $2.0 $2.5 $ -- $ -- $ 4.8
Prices based on models -- -- -- 1.1 6.9 8.0
- -------------------------------------------------------------------------------------------------------------
Total(2) $ .3 $2.0 $2.5 $1.1 $6.9 $12.8
=============================================================================================================
<FN>
(1) Broker quote sheets.
(2) Includes $12.6 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
</FN>
JCP&L 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 derivative instruments would not have
had a material effect on its consolidated financial position or cash flows as of
March 31, 2003.
Equity Price Risk
Included in JCP&L's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $51
million and $52 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $5 million reduction in fair value as of March 31, 2003.
97
Outlook
- -------
Beginning in 1999, all of JCP&L's customers were able to select
alternative energy suppliers. JCP&L continues to deliver power to homes and
businesses through its existing distribution system, which remains regulated. To
support customer choice, rates were restructured into unbundled service charges
and additional non-bypassable charges to recover stranded costs.
Regulatory assets are costs which have been authorized by the NJBPU
and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. All of JCP&L's regulatory assets are expected to continue
to be recovered under the provisions of the regulatory proceedings discussed
below. JCP&L's regulatory assets totaled $3.1 billion and $3.2 billion as of
March 31, 2003 and December 31, 2002, respectively.
Regulatory Matters
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L submitted two rate
filings with the NJBPU in August 2002. The first filing requested increases in
base electric rates of approximately $98 million annually. The second filing was
a request to recover deferred costs that exceeded amounts being recovered under
the current market transition charge and societal benefits charge rates; one
proposed method of recovery of these costs is the securitization of the deferred
balance. Hearings began in February 2003. On March 18, 2003, a report prepared
by independent auditors addressing costs deferred by JCP&L from August 1, 1999
through July 31, 2002, was transmitted to the Office of Administrative Law,
where JCP&L's rate case is being heard. While the auditors concluded that
JCP&L's energy procurement strategy and process was reasonable and prudent, they
identified potential disallowances approximating $17 million. The report
subjected $436 million of deferred costs to a retrospective prudence review
during a period of extreme price uncertainty and volatility in the energy
markets. Although JCP&L disagrees with the potential disallowances, it is
pleased with the report's major conclusions and overall tone. Hearings began in
February 2003. On March 18, 2003, a report prepared by independent auditors
addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002,
was transmitted to the Office of Administrative Law, where JCP&L's rate case is
being heard. While the auditors concluded that JCP&L's energy procurement
strategy and process was reasonable and prudent, they identified potential
disallowances approximating $17 million. The report subjected $436 million of
deferred costs to a retrospective prudence review during a period of extreme
price uncertainty and volatility in the energy markets. Although JCP&L disagrees
with the potential disallowances, it is pleased with the report's major
conclusions and overall tone. Hearings concluded on April 28, 2003, and initial
briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings
requesting an aggregate rate increase of approximately $122 million in base
electric rates and the recovery of deferred costs based on the securitization
methodology discussed above. If the securitization methodology is not allowed,
then JCP&L has requested deferred cost recovery over a four-year period with a
return on the unamortized deferred cost balance. This alternative would increase
the overall rate request to approximately $246 million. JCP&L strongly disagrees
with many of the positions taken by NJBPU Staff. The Staff's position would
result in a $119 million estimated annual earnings decrease related to the
electricity delivery charge. In addition, the Staff recommended disallowing
approximately $153 million of deferred energy costs which would result in a
one-time pre-tax charge against earnings of $153 million. JCP&L will respond to
the Staff's position in its Reply Brief which is due on May 21, 2003. The
Administrative Law Judge's recommended decision is due by the end of June 2003
and the NJBPU's subsequent decision is due in July 2003.
In 1997, the NJBPU authorized JCP&L to recover from customers,
subject to possible refund, $135 million of costs incurred in connection with a
1996 buyout of a power purchase agreement. JCP&L has recovered the full $135
million; the NJBPU has established a procedural schedule to take further
evidence with respect to the buyout to enable it to make a final prudence
determination contemporaneously with the resolution of the pending rate case.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The results of
the February 2002 auction, with the NJBPU's approval, removed JCP&L's BGS
obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In
February 2003, the auctioning of BGS for the period beginning August 1, 2003
took place. The auction covered a fixed price bid (applicable to all residential
and smaller commercial and industrial customers) and an hourly price bid
(applicable to all large industrial customers) process. JCP&L sells all
self-supplied energy (from non-utility generation power contracts and owned
generation) into the wholesale market with offsetting credits to its deferred
energy cost balances.
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
98
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 March 31, 2003, 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 a non-bypassable
societal benefits charge. JCP&L has accrued liabilities aggregating
approximately $47.1 million as of March 31, 2003. JCP&L does not believe
environmental remediation costs will have a material adverse effect on its
financial condition, cash flows or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against us, the most significant of which are
described above and below.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L. In an investigation into the causes of the
outages and the reliability of the transmission and distribution systems of all
four New Jersey electric utilities, the NJBPU concluded that there was not a
prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate
or improper service to its customers. In July 1999, two class action lawsuits
(subsequently consolidated into a single proceeding) were filed in New Jersey
Superior Court against JCP&L and other GPU companies, seeking compensatory and
punitive damages arising from the July 1999 service interruptions in its service
territory. In May 2001, the court denied without prejudice JCP&L's motion
seeking decertification of the class. Discovery continues in the class action,
but no trial date has been set. In October 2001, the court held argument on the
plaintiffs' motion for partial summary judgment, which contends that JCP&L is
bound to several findings of the NJBPU investigation. The plaintiffs' motion was
denied by the Court in November 2001 and the plaintiffs' motion to file an
appeal of this decision was denied by the New Jersey Appellate Division. JCP&L
has also filed a motion for partial summary judgment that is currently pending
before the Superior Court. JCP&L is unable to predict the outcome of these
matters.
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. Assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting those specific factors. JCP&L's more significant accounting policies
are described below.
Purchase Accounting
The merger between FirstEnergy and GPU 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 were finalized in the fourth
quarter of 2002, 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. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," JCP&L evaluates its
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in
JCP&L's evaluations of goodwill reflect operations consistent with its general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on JCP&L's future evaluations of goodwill. As of March 31,
2002, JCP&L had recorded goodwill of approximately $2.0 billion related to the
merger.
Regulatory Accounting
JCP&L is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the 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. As of March 31, 2003, JCP&L's
regulatory assets totaled $3.1 billion. 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.
99
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 JCP&L's normal operations, it 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 been
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 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
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
100
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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 asset 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).
Recently Issued Accounting Standards Not Yet Implemented
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (JCP&L's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
JCP&L currently has transactions with entities in connection with the
sale of preferred securities and debt secured by bondable property, and which
are reasonably possible of meeting the definition of a VIE in accordance with
FIN 46. JCP&L currently consolidates those entities and believes it will
continue to consolidate following the adoption of FIN 46.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS133 for decisions made by the Derivative Implementation Group, as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for quarters
which began prior to June 15, 2003, which continue to be applied based on their
original effective dates. JCP&L is currently assessing the new standard and has
not yet determined the impact on its financial statements.
101
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2003 2002
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $251,203 $245,790
-------- --------
OPERATING EXPENSES AND TAXES:
Purchased power.............................................................. 143,461 136,140
Other operating costs........................................................ 32,512 29,005
-------- --------
Total operation and maintenance expenses................................. 175,973 165,145
Provision for depreciation and amortization.................................. 27,161 15,292
General taxes................................................................ 16,860 16,912
Income taxes................................................................. 7,198 14,871
-------- --------
Total operating expenses and taxes....................................... 227,192 212,220
-------- --------
OPERATING INCOME................................................................ 24,011 33,570
OTHER INCOME.................................................................... 5,168 5,131
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 29,179 38,701
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 10,539 10,455
Allowance for borrowed funds used during construction........................ (73) (284)
Deferred interest............................................................ (440) (193)
Other interest expense....................................................... 463 273
Subsidiary's preferred stock dividend requirements........................... 1,890 1,838
-------- --------
Net interest charges..................................................... 12,379 12,089
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 16,800 26,612
Cumulative effect of accounting change (net of income taxes
of $154,000) (Note 5) 217 --
-------- --------
NET INCOME...................................................................... $ 17,017 $ 26,612
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Metropolitan
Edison Company are an integral part of these statements.
</FN>
102
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,815,666 $1,620,613
Less--Accumulated provision for depreciation.............................. 744,297 547,925
---------- ----------
1,071,369 1,072,688
Construction work in progress.............................................. 16,394 16,078
---------- ----------
1,087,763 1,088,766
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 156,015 155,690
Long-term notes receivable from associated companies...................... 12,418 12,418
Other..................................................................... 27,283 19,206
---------- ----------
195,716 187,314
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 212,571 15,685
Receivables-
Customers (less accumulated provisions of $5,451,000 and $4,810,000
respectively, for uncollectible accounts)............................. 119,873 120,868
Associated companies.................................................... 5,609 23,219
Other................................................................... 18,496 18,235
Notes receivable from associated companies................................ 8,005 --
Material and supplies, at average cost.................................... 139 --
Prepayments and other..................................................... 39,871 9,731
---------- ----------
404,564 187,738
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 1,126,936 1,179,125
Goodwill.................................................................. 885,832 885,832
Other..................................................................... 37,631 36,030
---------- ----------
2,050,399 2,100,987
---------- ---------
$3,738,442 $3,564,805
========== ==========
103
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares -
859,500 shares outstanding............................................ $1,297,784 $1,297,784
Accumulated other comprehensive loss.................................... (13) (39)
Retained earnings....................................................... 34,857 17,841
---------- ----------
Total common stockholder's equity................................... 1,332,628 1,315,586
Company-obligated trust preferred securities.............................. 92,461 92,409
Long-term debt............................................................ 646,932 538,790
---------- ----------
2,072,021 1,946,785
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 160,467 60,467
Accounts payable-
Associated companies.................................................... 86,162 56,861
Other................................................................... 31,250 28,583
Notes payable to associated companies..................................... 65,212 88,299
Accrued taxes............................................................. 4,180 16,096
Accrued interest.......................................................... 11,650 16,448
Other..................................................................... 11,960 11,690
---------- ----------
370,881 278,444
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 324,698 316,757
Accumulated deferred investment tax credits............................... 12,313 12,518
Purchase power contract loss liability.................................... 650,947 660,507
Nuclear fuel disposal costs............................................... 37,655 37,541
Nuclear plant decommissioning costs....................................... -- 270,611
Asset retirement obligation............................................... 201,192 --
Other..................................................................... 68,735 41,642
---------- ----------
1,295,540 1,339,576
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$3,738,442 $3,564,805
========== ==========
<FN>
The preceding Notes to Financial Statements as they relate to Metropolitan
Edison Company are an integral part of these balance sheets.
</FN>
104
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2003 2002
--------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................................... $ 17,017 $ 26,612
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........................... 27,161 15,292
Deferred costs, net................................................... (3,820) (6,920)
Deferred income taxes, net............................................ 1,385 7,882
Investment tax credits, net........................................... (205) (212)
Receivables........................................................... 18,344 12,914
Materials and supplies................................................ (139) --
Accounts payable...................................................... 31,968 (20,812)
Cumulative effect of accounting change (Note 5)....................... (371) --
Accrued taxes......................................................... (11,916) (1,351)
Accrued interest...................................................... (4,798) (6,833)
Prepayments and other................................................. (30,140) (26,897)
Other................................................................. (11,717) (17,188)
-------- --------
Net cash provided from (used for) operating activities.............. 32,769 (17,513)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt.......................................................... 247,696 --
Short-term borrowings, net.............................................. -- 55,547
Redemptions and Repayments-
Long-term debt.......................................................... (40,000) (30,000)
Short-term borrowings, net.............................................. (23,087) --
-------- --------
Net cash provided from (used for) financing activities.............. 184,609 25,547
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................ (10,333) (9,096)
Notes receivable-associated companies, net................................ (2,371) (3,161)
Other..................................................................... (7,788) (239)
-------- --------
Net cash provided from (used for) investing activities.............. (20,492) (12,496)
-------- --------
Net increase (decrease) in cash and cash equivalents......................... 196,886 (4,462)
Cash and cash equivalents at beginning of period ............................ 15,685 25,274
-------- --------
Cash and cash equivalents at end of period................................... $212,571 $ 20,812
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to Metropolitan
Edison Company are an integral part of these statements.
</FN>
105
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors of Metropolitan
Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan
Edison Company and its subsidiaries as of March 31, 2003, and the related
consolidated statements of income and cash flows for the three-month periods
ended March 31, 2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
106
METROPOLITAN EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
Met-Ed provides regulated transmission and distribution services in
eastern and south central Pennsylvania. Pennsylvania customers are able to
choose their electricity suppliers as a result of legislation which restructured
the electric utility industry. Met-Ed's regulatory plan required unbundling the
price for electricity into its component elements - including generation,
transmission, distribution and transition charges. Met-Ed continues to deliver
power to homes and businesses through its existing distribution system and
maintains provider of last resort (PLR) obligations to customers who elect to
retain Met-Ed as their power supplier.
Results of Operations
- ---------------------
Net income in the first quarter of 2003 decreased to $17.0 million
from $26.6 million in the first quarter of 2002. Net income in the first quarter
of 2003 included an after-tax credit of $0.2 million from the cumulative effect
of an accounting change due to the adoption of SFAS No. 143, "Accounting for
Asset Retirement Obligations." Income before the cumulative effect was $16.8
million in the first three months of 2003 compared with $26.6 million in the
corresponding period of 2002. Higher operating expenses primarily due to
increases in depreciation and amortization and purchased power costs were
partially offset by higher distribution revenues.
Electric Sales
Operating revenues increased by $5.4 million, or 2.2% in the first
quarter of 2003 compared with the same period of 2002. The higher revenues
resulted from increased distribution deliveries to residential and commercial
customers partially offset by lower wholesale kilowatt-hour sales. Distribution
deliveries increased 9.9% in the first quarter of 2003 from the same quarter of
the prior year, increasing revenues from electricity throughput by $8.9 million.
Distribution deliveries benefited from higher residential and commercial demand,
due in large part to colder temperatures, which was partially offset by a
decrease in industrial demand from the continued effect of a sluggish economy.
In the first quarter of 2003, more commercial and industrial customers chose an
alternate power supplier compared with the same period of 2002, which held down
the increase in retail generation kilowatt-hour sales. Generation kilowatt-hour
sales increased 1.4% consisting of higher residential and commercial sales
(22.9% and 4.9%, respectively) offset by a 35.8% decrease in industrial sales,
partially reflecting the increased shopping by commercial and industrial
customers. Wholesale sales revenues decreased $7.0 million principally due to a
reduction in kilowatt-hour sales to affiliated companies.
Changes in electric generation sales and distribution deliveries in the
first quarter of 2003 from the same quarter of 2002 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
---------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. 1.4%
Wholesale............................... (99.9)%
----------------------------------------------------
Total Electric Generation Sales........... (7.4)%
====================================================
Distribution Deliveries:
Residential............................. 22.7%
Commercial.............................. 11.3%
Industrial.............................. (6.3)%
---------------------------------------------------
Total Distribution Deliveries............. 9.9%
===================================================
107
Operating Expenses and Taxes
Total operating expenses and taxes increased $15.0 million in the
first quarter of 2003 from the first quarter of 2002, primarily due to increases
in purchased power costs and depreciation and amortization charges. The
following table presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------------
Increase (Decrease) (In millions)
Purchased power costs............................ 7.3
Other operating costs............................ 3.5
--------------------------------------------------------------
Total operation and maintenance expenses....... 10.8
Provision for depreciation and amortization...... 11.9
General taxes.................................... --
Income taxes..................................... (7.7)
--------------------------------------------------------------
Total operating expenses and taxes............. $15.0
===============================================================
Higher purchased power costs in the first quarter of 2003, compared
with the first quarter of 2002, were primarily due to higher average unit costs.
The increase in depreciation and amortization charges of $11.9 million reflected
an increase in amortization of regulatory assets being recovered through the
competitive transition charge (CTC). Other operating costs increased by $3.5
million as a result of higher pension and other employee benefit costs, as well
as increased uncollectible customer accounts and insurance expenses.
Net Interest Charges
Net interest charges increased by $0.3 million in the first quarter
of 2003 compared with the first quarter of 2002. The increase reflects the
issuance of $250 million of new senior notes in March 2003 that will be used for
redeeming outstanding long-term debt later in 2003. Partially offsetting that
increase was the redemption of $40 million of notes in the first quarter of
2003.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, Met-Ed
recorded an after-tax credit to net income of approximately $0.2 million. Met-Ed
identified applicable legal obligations as defined under the new accounting
standard for nuclear power plant decommissioning. As a result of adopting SFAS
143 in January 2003, asset retirement costs of $186 million were recorded as
part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $186 million. The asset retirement obligation (ARO)
liability at the date of adoption was $198 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, Met-Ed had recorded decommissioning
liabilities of $260 million. Met-Ed expects substantially all of its nuclear
decommissioning costs to be recoverable in rates over time. Therefore, Met-Ed
recognized a regulatory liability of $61 million upon adoption of SFAS 143 for
the transition amounts related to establishing the ARO for nuclear
decommissioning. The remaining cumulative effect adjustment for unrecognized
depreciation and accretion offset by the reduction in the liabilities was a $0.4
million increase to income, or $0.2 million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
Met-Ed's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and optional debt
redemptions are expected to be met without increasing its net debt and preferred
stock outstanding. Over the next three years, Met-Ed expects to meet its
contractual obligations with cash from operations. Thereafter, Met-Ed expects to
use a combination of cash from operations and funds from the capital markets.
Changes in Cash Position
As of March 31, 2003, Met-Ed had $212.6 million of cash and cash
equivalents (principally to be used for the redemption of long-term debt in the
second quarter of 2003) compared with $15.7 million as of December 31, 2002. The
major sources for changes in these balances are summarized below.
108
Cash Flows From Operating Activities
Cash flows provided from (used for) operating activities in the first
quarter of 2003 and 2002 were as follows:
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 41 $42
Working capital and other............ (8) (60)
-------------------------------------------------------------
Total................................ $33 $(18)
=============================================================
(1) Includes net income, depreciation and
amortization, deferred costs recoverable as
regulatory assets, deferred income taxes,
investment tax credits and major noncash
credits.
Net cash from operating activities increased to $33 million in the
first quarter of 2003 compared with net cash used for operating activities in
the first quarter of 2002 of $18 million. The increase was due to a $52 million
increase in funds from working capital and other, primarily from changes in
accounts payable.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash provided from financing
activities of $185 million reflected the issuance of $250 million of senior
notes, partially offset by the redemption of $40 million of long-term debt and
$23 million of short-term debt. In the first quarter of 2002, net cash provided
from financing activities totaled $26 million, due to an increase in short-term
debt, partially offset by the redemption of long-term debt.
As of March 31, 2003, Met-Ed had approximately $220.6 million of cash
and temporary investments and approximately $65.2 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 (FMB) other than as collateral for
senior notes, since its senior note indentures prohibit (subject to certain
exceptions) it from issuing any debt which is senior to the senior notes. As of
March 31, 2003, Met-Ed had the capability to issue $14 million of additional
senior notes based upon FMB collateral. Met-Ed had no restrictions on the
issuance of preferred stock.
Cash Flows From Investing Activities
Net cash flows used in investing activities totaled $20 million in
the first quarter of 2003, compared to the same period of 2002. The net cash
flows used for investing resulted from property additions and loans to
associated companies. Expenditures for property additions primarily support
Met-Ed's energy delivery operations. In the first quarter of 2002, net cash
flows used in investing activities totaled $12 million, principally due to
property additions.
During the remaining quarters of 2003, capital requirements for
property additions are expected to be about $42 million. Met-Ed has additional
requirements of approximately $20 million for maturing long-term debt during the
remainder of 2003. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements; restricted cash as of March
31, 2003 was available for optional debt redemptions later in 2003.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including Met-Ed.
109
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including Met-Ed. Moody's noted that merger debt had put pressure on
FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all
levels within the company although those plans had been delayed by external
events.
Market Risk Information
- -----------------------
Met-Ed uses various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price 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
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, it uses a variety of non-derivative and derivative instruments,
including options and future contracts. The derivatives are used for hedging
purposes. Most of Met-Ed'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 the first quarter of 2003 is summarized in the following table:
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
Non-Hedge Hedge Total
- ------------------------------------------------------------------------------------------------
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2003................... $17.4 $ 0.1 $17.5
New contract value when entered............................... -- -- --
Additions/Increase in value of existing contracts............. 8.2 -- 8.2
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. -- (0.1) (0.1)
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2003 (1)... $25.6 $ -- $25.6
=================================================================================================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $ 0.1 $ 0.1
Regulatory Liability.......................................... $ 8.2 $ -- $ 8.2
<FN>
(1) Includes $25.6 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
</FN>
Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
Non-Hedge Hedge Total
----------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $-- $ -- $--
Non-Current-
Other Deferred Charges............ 25.6 -- 25.6
---------------------------------------------------------------------
Net assets........................ $25.6 $ -- $25.6
=====================================================================
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 uses these results to develop
estimates of fair value for financial reporting purposes and for internal
management decision making. Sources of information for the valuation of
derivative contracts by year are summarized in the following table:
110
Source of Information
- - Fair Value by Contract Year 2003 2004 2005 2006 Thereafter Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(1) $.6 $4.0 $5.0 $ -- $ -- $ 9.6
Prices based on models -- -- -- 2.3 13.7 16.0
- --------------------------------------------------------------------------------------------------------------
Total(2) $.6 $4.0 $5.0 $2.3 $13.7 $25.6
==============================================================================================================
<FN>
(1) Broker quote sheets.
(2) Includes $25.1 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
</FN>
Met-Ed 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 derivative instruments would not have
had a material effect on its consolidated financial position or cash flows as of
March 31, 2003.
Equity Price Risk
Included in Met-Ed's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $79
million and $81 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $8 million reduction in fair value as of March 31, 2003.
Outlook
- -------
Beginning in 1999, all of Met-Ed's customers were able to select
alternative energy suppliers. Met-Ed continues to deliver power to homes and
businesses through its existing distribution system, which remains regulated.
The Pennsylvania Public Utility Commission (PPUC) authorized Met-Ed's rate
restructuring plan, establishing separate charges for transmission,
distribution, generation and stranded cost recovery, which is recovered through
a CTC. Customers electing to obtain power from an alternative supplier have
their bills reduced based on the regulated generation component, and the
customers receive a generation charge from the alternative supplier. Met-Ed has
a continuing responsibility to provide power to those customers not choosing to
receive power from an alternative energy supplier, subject to certain limits,
which is referred to as its PLR obligation.
Regulatory assets are costs which have been authorized by the PPUC
and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. All of Met-Ed's regulatory assets are expected to continue
to be recovered under the provisions of the regulatory plan as discussed below.
Met-Ed's regulatory assets totaled $1.1 billion and $1.2 billion as of March 31,
2003 and December 31, 2002, respectively.
Regulatory Matters
Effective September 1, 2002, Met-Ed assigned its PLR responsibility
to its unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through
a wholesale power sale agreement which expires in December 2003 and may be
extended for each successive calendar year. Under the terms of the wholesale
agreement, FES assumed the supply obligation, and the energy supply profit and
loss risk, for the portion of power supply requirements that Met-Ed does not
self-supply under its non-utility generation (NUG) contracts and other existing
power contracts with nonaffiliated third party suppliers. This arrangement
reduces its exposure to high wholesale power prices by providing power at or
below the shopping credit for its uncommitted PLR energy costs during the term
of the agreement to FES. Met-Ed will continue to defer the cost differences
between NUG contract rates and the rates reflected in its capped generation
rates.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the Commonwealth Court's decision which effectively affirmed the
PPUC's order approving the merger between FirstEnergy and GPU, let stand the
Commonwealth Court's denial of Met-Ed's PLR rate relief and remanded the merger
savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger
savings issue to the Office of Administrative Law for hearings and directed
Met-Ed to file a position paper on the effect of the Commonwealth Court's order
on the Settlement Stipulation by May 2, 2003. Because Met-Ed had already
reserved for the deferred energy costs and FES has largely hedged Met-Ed's
anticipated PLR energy supply requirements through 2005, Met-Ed believes that
the disallowance of CTC recovery of PLR costs above its capped generation rates
will not have a future adverse financial impact during that period.
111
Environmental Matters
Met-Ed 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 March 31, 2003, based on estimates of the total
costs of cleanup, Met-Ed's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. Met-Ed has accrued
liabilities aggregating approximately $0.2 million as of March 31, 2003. Met-Ed
does not believe environmental remediation costs will have a material adverse
effect on its financial condition, cash flows or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against Met-Ed, the most significant of which
are described above.
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 its financial results. All of its 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 those specific factors. Met-Ed's more significant accounting policies
are described below.
Purchase Accounting
The merger between FirstEnergy and GPU 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 were finalized in the fourth
quarter of 2002, 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. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," Met-Ed evaluates its
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in
Met-Ed's evaluations of goodwill reflect operations consistent with its general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on its future evaluations of goodwill. As of March 31, 2003,
Met-Ed had recorded goodwill of approximately $885.8 million related to the
merger.
Regulatory Accounting
Met-Ed is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the costs that the regulatory
agencies determine it 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. As of March 31, 2003, Met-Ed's
regulatory assets totaled $1.1 billion. Met-Ed regularly reviews these assets to
assess its 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. Met-Ed continually monitors its derivative contracts to
112
determine if its activities, expectations, intentions, assumptions and estimates
remain valid. As part of Met-Ed's normal operations, it 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 been
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 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
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing
to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy
included the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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
113
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, Met-Ed would recognize a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (Met-Ed's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
Met-Ed currently has transactions with entities in connection with
the sale of preferred securities, which may fall within the scope of this
interpretation, and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. Met-Ed currently consolidates these entities and
believes it will continue to consolidate following the adoption of FIN 46.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS 133 for decisions made by the Derivative Implementation Group, as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective of quarters which
began prior to June 15, 2003, which continue to be applied based on their
original effective dates. Met-Ed is currently assessing the new standard and has
not yet determined the impact on its financial statements.
114
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2003 2002
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $254,876 $242,820
-------- --------
OPERATING EXPENSES AND TAXES:
Purchased power.............................................................. 173,236 138,129
Other operating costs........................................................ 36,551 33,800
-------- --------
Total operation and maintenance expenses................................. 209,787 171,929
Provision for depreciation and amortization.................................. 13,773 14,831
General taxes................................................................ 15,744 15,030
Income taxes................................................................. 2,893 12,499
-------- --------
Total operating expenses and taxes....................................... 242,197 214,289
-------- --------
OPERATING INCOME................................................................ 12,679 28,531
OTHER INCOME (EXPENSE).......................................................... (192) 298
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 12,487 28,829
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 7,339 8,421
Allowance for borrowed funds used during construction........................ (81) (120)
Deferred interest............................................................ (996) (751)
Other interest expense ...................................................... 143 605
Subsidiary's preferred stock dividend requirements........................... 1,888 1,835
-------- --------
Net interest charges..................................................... 8,293 9,990
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 4,194 18,839
Cumulative effect of accounting change (net of income taxes of
$777,000) (Note 5) ........................................................... 1,096 --
-------- --------
NET INCOME...................................................................... $ 5,290 $ 18,839
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to the Pennsylvania
Electric Company are an integral part of these statements.
</FN>
115
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,944,053 $1,844,999
Less--Accumulated provision for depreciation.............................. 752,152 647,581
---------- ----------
1,191,901 1,197,418
Construction work in progress-
Electric plant.......................................................... 18,135 19,200
---------- ----------
1,210,036 1,216,618
OTHER PROPERTY AND INVESTMENTS:
Non-utility generation trusts............................................. 6,370 109,881
Nuclear plant decommissioning trusts...................................... 87,925 88,818
Long-term notes receivable from associated companies...................... 15,515 15,515
Other..................................................................... 13,400 9,425
---------- ----------
123,210 223,639
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 310 10,310
Receivables-
Customers (less accumulated provisions of $6,881,000 and $6,216,000
respectively, for uncollectible accounts)............................ 118,776 128,303
Associated companies.................................................... 40,143 45,236
Other................................................................... 25,364 16,184
Prepayments and other..................................................... 37,330 2,551
---------- ----------
221,923 202,584
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 543,699 599,663
Goodwill.................................................................. 898,086 898,086
Deferred income taxes..................................................... 30,138 1,517
Other..................................................................... 21,601 21,147
---------- ----------
1,493,524 1,520,413
---------- ----------
$3,048,693 $3,163,254
========== ==========
116
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
----------- ------------
(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................................................... 1,215,256 1,215,256
Accumulated other comprehensive loss.................................... (61) (69)
Retained earnings....................................................... 37,995 32,705
---------- ----------
Total common stockholder's equity................................... 1,359,002 1,353,704
Company-obligated trust preferred securities ............................. 92,267 92,214
Long-term debt............................................................ 469,800 470,274
---------- ----------
1,921,069 1,916,192
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 827 813
Accounts payable-
Associated companies.................................................... 137,152 129,906
Other................................................................... 31,110 29,690
Notes payable to associated companies..................................... -- 90,427
Accrued taxes............................................................. 48,556 21,271
Accrued interest.......................................................... 18,374 12,695
Other..................................................................... 8,522 8,409
---------- ----------
244,541 293,211
---------- ----------
DEFERRED CREDITS:
Accumulated deferred investment tax credits............................... 10,677 10,924
Nuclear plant decommissioning costs....................................... -- 135,450
Nuclear fuel disposal costs............................................... 18,827 18,771
Power purchase contract loss liability.................................... 727,220 765,063
Asset retirement obligation............................................... 100,596 --
Other..................................................................... 25,763 23,643
---------- ----------
883,073 953,851
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$3,048,693 $3,163,254
========== ==========
<FN>
The preceding Notes to Financial Statements as they relate to the Pennsylvania
Electric Company are an integral part of these balance sheets.
</FN>
117
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
---------------------------
2003 2002
-------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................................. $ 5,290 $ 18,839
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........................... 13,773 14,831
Other amortization.................................................... (14) 782
Deferred costs, net................................................... (92) (18,434)
Deferred income taxes, net............................................ (41,640) (6,304)
Investment tax credits, net........................................... (247) (285)
Receivables........................................................... 5,440 11,803
Accounts payable...................................................... 8,666 (11,822)
Cumulative effect of accounting change (Note 5)....................... (1,873) --
Accrued taxes......................................................... 27,284 15,262
Accrued interest...................................................... 5,679 6,089
Prepayments and other................................................. (34,778) (28,844)
Other, net............................................................ (7,076) (6,692)
-------- --------
Net cash provided from (used for) operating activities.............. (19,588) (4,775)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Short-term borrowings, net.............................................. (90,427) (39,573)
-------- --------
Net cash used for (provided from) financing activities.................... (90,427) (39,573)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................ (6,312) (10,194)
Proceeds from non-utility generation trusts............................... 106,327 34,208
Other, net................................................................ -- (239)
-------- --------
Net cash used for (provided from) investing activities.............. 100,015 23,775
-------- --------
Net decrease in cash and cash equivalents.................................... (10,000) (20,573)
Cash and cash equivalents at beginning of period ............................ 10,310 39,033
-------- --------
Cash and cash equivalents at end of period................................... $ 310 $ 18,460
======== ========
<FN>
The preceding Notes to Financial Statements as they relate to the Pennsylvania
Electric Company are an integral part of these statements.
</FN>
118
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors of Pennsylvania
Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania
Electric Company and its subsidiaries as of March 31, 2003, and the related
consolidated statements of income and cash flows for the three-month periods
ended March 31, 2003 and 2002. These interim 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 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003
119
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
Penelec provides regulated transmission and distribution services in
northern, western and south central Pennsylvania. Pennsylvania customers are
able to choose their electricity suppliers as a result of legislation which
restructured the electric utility industry. Penelec's regulatory plan required
unbundling the price for electricity into its component elements - including
generation, transmission, distribution and transition charges. Penelec continues
to deliver power to homes and businesses through its existing distribution
system and maintains provider of last resort (PLR) obligations to customers who
elect to retain Penelec as their power supplier.
Results from Operations
- -----------------------
Net income in the first quarter of 2003 decreased to $5.3 million
from $18.8 million in the first quarter of 2002. Net income in the first quarter
of 2003 included an after-tax credit of $1.1 million from the cumulative effect
of an accounting change due to the adoption of SFAS No. 143, "Accounting for
Asset Retirement Obligations." Income before the cumulative effect was $4.2
million in the first three months of 2003 compared with $18.8 million for the
corresponding period of 2002. Higher operating expenses, primarily due to
purchased power costs, were partially offset by higher operating revenues.
Electric Sales
Operating revenues increased by $12.1 million or 5.0% in the first
quarter of 2003 compared with the same period in 2002. The higher revenues
resulted from higher distribution deliveries to residential and commercial
customers which were partially offset by lower industrial kilowatt-hour sales.
Distribution deliveries increased 6.7% in the first quarter of 2003 from the
same quarter of the prior year, increasing revenues from electricity throughput
by $7.1 million. Distribution deliveries benefited from higher residential and
commercial demand, due in large part to colder temperatures, which was partially
offset by a decrease in industrial demand from the continued effect of a
sluggish economy. Penelec's generation kilowatt-hour sales increase of 2.7%
reflected higher residential and commercial sales (17.3% and 9.9%, respectively)
offset by a 19.3% decrease in industrial sales growth. The substantial decrease
in industrial sales was primarily due to more industrial customers being served
by alternative suppliers in the first quarter of 2003 compared to the same
period of 2002. Retail generation sales revenue increases of $4.3 million were
partially offset by a decrease in wholesale sales revenues of $0.7 million.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the first quarter of 2002 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
--------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ 2.7%
Wholesale............................. (109.7)%
--------------------------------------------------
Total Electric Generation Sales......... (0.3)%
==================================================
Distribution Deliveries:
Residential........................... 17.2%
Commercial............................ 11.0%
Industrial............................ (6.5)%
-------------------------------------------------
Total Distribution Deliveries........... 6.7%
=================================================
120
Operating Expenses and Taxes
Total operating expenses and taxes increased $27.9 million or 13.0%
in the first quarter of 2003 from the first quarter of 2002, primarily due to
increases in purchased power costs. The following table presents changes during
the first quarter of 2003 from the same period in 2002 for operating expenses
and taxes.
Operating Expenses and Taxes - Changes
- -----------------------------------------------------------------
Increase (Decrease) (In millions)
Purchased power costs............................ 35.1
Other operating costs............................ 2.8
- --------------------------------------------------------------
Total operation and maintenance expenses....... 37.9
Provision for depreciation and amortization...... (1.1)
General taxes.................................... 0.7
Income taxes..................................... (9.6)
- ---------------------------------------------------------------
Total operating expenses and taxes............. $27.9
==============================================================
Higher purchased power costs in the first quarter of 2003, compared
with the same quarter of 2002, were due to higher average unit costs and
increased kilowatt-hour purchases to meet greater retail generation sales
requirements. The increase in other operating costs is primarily due to higher
pension and other employee benefit costs and uncollectible customer accounts.
Net Interest Charges
Net interest charges decreased by $1.7 million in the first quarter
of 2003 compared with the first quarter of 2002, reflecting debt redemptions
since the end of the first quarter of 2002.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, Penelec
recorded an after-tax credit to net income of $1.1 million. Penelec identified
applicable legal obligations as defined under the new standard for nuclear power
plant decommissioning. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $93 million were recorded as part of the carrying amount of
the related long-lived asset, offset by accumulated depreciation of $93 million.
The asset retirement obligation (ARO) liability at the date of adoption was $99
million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, Penelec
had recorded decommissioning liabilities of $130 million. Penelec expects
substantially all of its nuclear decommissioning costs to be recoverable in
rates over time. Therefore, Penelec recognized a regulatory liability of $29
million upon adoption of SFAS 143 for the transition amounts related to
establishing the ARO for nuclear decommissioning. The remaining cumulative
effect adjustment for unrecognized depreciation and accretion offset by the
reduction in the liabilities was a $1.9 million increase to income, or the $1.1
million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
Penelec's cash requirements in 2003 for operating expenses,
construction expenditures and scheduled debt maturities are expected to be met
without increasing its net debt and preferred stock outstanding. Over the next
three years, Penelec expects to meet its contractual obligations with cash from
operations. Thereafter, Penelec expects to use a combination of cash from
operations and funds from the capital markets.
Changes in Cash Position
As of March 31, 2003, Penelec had $0.3 million of cash and cash
equivalents, compared with $10.3 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash used for operating activities was $20 million in the first
quarter of 2003 and $5 million in the first quarter of 2002. Cash flows used by
operating activities in the first quarter of 2003 and 2002 were as follows:
121
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ (25) $ 9
Working capital and other............ 5 (14)
-------------------------------------------------------------
Total................................ $(20) $ (5)
=============================================================
(1) Includes net income, depreciation and
amortization, deferred costs recoverable as
regulatory assets, deferred income taxes,
investment tax credits and major noncash
credits.
Net cash used for operating activities increased to $20 million in
the first quarter of 2003 from $5 million in the same period of 2002. This
increase was due to the decrease of cash earnings primarily resulting from
higher purchased power costs.
Cash Flows From Financing Activities
Net cash used for financing activities of $90 million and $40 million
in the first quarter of 2003 and the first quarter of 2002, respectively,
represents the redemptions of short-term debt.
As of March 31, 2003, Penelec had about $0.3 million of cash and no
short-term indebtedness. Penelec may borrow from its affiliates on a short-term
basis. Penelec will not issue first mortgage bonds (FMB) other than as
collateral for senior notes, since its senior note indentures prohibit (subject
to certain exceptions) it from issuing any debt which is senior to the senior
notes. As of March 31, 2003, Penelec had the capability to issue $3 million of
additional senior notes based upon FMB collateral. Penelec had no restrictions
on the issuance of preferred stock.
Cash Flows From Investing Activities
Net cash flows provided from investing activities totaled $100
million in the first quarter of 2003, compared with $24 million in the same
period of 2002. The net cash flows provided from investing activities resulted
from proceeds from nonutility generation trusts, slightly offset by property
additions in both periods. Expenditures for property additions primarily support
Penelec's energy delivery operations.
During the remaining quarters of 2003, capital requirements for
property additions are expected to be about $43 million. Penelec has additional
requirements of approximately $221 million for maturing long-term debt during
the remainder of 2003. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including Penelec.
On April 11, 2003 Moody's Investors Service affirmed its existing
ratings for FirstEnergy. Moody's noted that the ratings were based on the stable
business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for
the EUOC, including Penelec. Moody's noted that merger debt had put pressure on
FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all
levels within the company although those plans had been delayed by external
events.
Market Risk Information
- -----------------------
Penelec uses various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price fluctuations.
FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises
an
122
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, it uses a variety of non-derivative and derivative instruments,
including options and future contracts. The derivatives are used for hedging
purposes. Most of Penelec'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 the first quarter of 2003 is summarized in the following table:
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
Non-Hedge Hedge Total
- ------------------------------------------------------------------------------------------------
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2003................... $ 8.7 $ 0.1 $ 8.8
New contract value when entered............................... -- -- --
Additions/Increase in value of existing contracts............. 4.1 -- 4.1
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. -- (0.1) (0.1)
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2003 (1)... $12.8 $ -- $ 12.8
=================================================================================================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................ $ .2 $ -- $ .2
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $(0.1) $ (0.1)
Regulatory Liability.......................................... $ 3.9 $ -- $ 3.9
<FN>
(1) Includes $12.8 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled contracts and
changes in techniques/assumptions.
</FN>
Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
Non-Hedge Hedge Total
----------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $ -- $ -- $ --
Non-Current-
Other Deferred Charges............ 12.8 -- 12.8
---------------------------------------------------------------------
Net assets........................ $12.8 $ -- $12.8
=====================================================================
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 uses these results to develop
estimates of fair value for financial reporting purposes and for internal
management decision making. Sources of information for the valuation of
derivative contracts by year are summarized in the following table:
Source of Information
- - Fair Value by Contract Year 2003 2004 2005 2006 Thereafter Total
- ------------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(1) $ .2 $2.0 $2.5 $ -- $ -- $ 4.7
Prices based on models -- -- -- 1.2 6.9 8.1
- -----------------------------------------------------------------------------------------------------------
Total(2) $ .2 $2.0 $2.5 $1.2 $6.9 $12.8
===========================================================================================================
<FN>
(1) Broker quote sheets.
(2) Includes $12.6 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
</FN>
Penelec 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 derivative instruments would not have
had a material effect on its consolidated financial position or cash flows as of
March 31, 2003.
123
Equity Price Risk
Included in Penelec's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $41
million and $42 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $4 million reduction in fair value as of March 31, 2003.
Outlook
- -------
Beginning in 1999, all of Penelec's customers were able to select
alternative energy suppliers. Penelec continues to deliver power to homes and
businesses through its existing distribution system, which remains regulated.
The Pennsylvania Public Utility Commission (PPUC) authorized Penelec's rate
restructuring plan, establishing separate charges for transmission,
distribution, generation and stranded cost recovery, which is recovered through
a competitive transition charge (CTC). Customers electing to obtain power from
an alternative supplier have their bills reduced based on the regulated
generation component, and the customers receive a generation charge from the
alternative supplier. Penelec has a continuing responsibility to provide power
to those customers not choosing to receive power from an alternative energy
supplier, subject to certain limits, which is referred to as its PLR obligation.
Regulatory assets are costs which have been authorized by the PPUC
and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. All of Penelec's regulatory assets are expected to
continue to be recovered under the provisions of the regulatory plan as
discussed below. Penelec's regulatory assets totaled $544 million and $600
million as of March 31, 2003 and December 31, 2002, respectively.
Regulatory Matters
Effective September 1, 2002, Penelec assigned its provider of last
resort (PLR) responsibility obligation to its unregulated supply affiliate,
FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement
which expires in December 2003 and may be extended for each successive calendar
year. Under the terms of the wholesale agreement, FES assumed the supply
obligation, and the energy supply profit and loss risk, for the portion of power
supply requirements that Penelec does not self-supply under its non-utility
generation (NUG) contracts and other existing power contracts with nonaffiliated
third party suppliers. This arrangement reduces its exposure to high wholesale
power prices by providing power at or below the shopping credit for its
uncommitted PLR energy costs during the term of the agreement to FES. Penelec
will continue to defer those cost differences between NUG contract rates and the
rates reflected in its capped generation rates.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the Commonwealth Court's decision which effectively affirmed the
PPUC's order approving the merger between FirstEnergy and GPU, let stand the
Commonwealth Court's denial of Penelec's PLR rate relief and remanded the merger
savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger
savings issue to the Office of Administrative Law for hearings and directed
Penelec to file a position paper on the effect of the Commonwealth Court's order
on the Settlement Stipulation by May 2, 2003. Because Penelec had already
reserved for the deferred energy costs and FES has largely hedged Penelec's
anticipated PLR energy supply requirements through 2005, Penelec believes that
the disallowance of CTC recovery of PLR costs above its capped generation rates
will not have a future adverse financial impact during that period.
Environmental Matters
Penelec 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 March 31, 2003, based on estimates of the total
costs of cleanup, Penelec's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. Penelec has total
accrued liabilities aggregating approximately $0.3 million as of March 31, 2003.
Penelec does not believe environmental remediation costs will have a material
adverse effect on its financial condition, cash flows or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to Penelec's normal
business operations are pending against it, the most significant of which are
described above.
124
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 its financial results. All of its 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 those specific factors. Penelec's more significant accounting
policies are described below.
Purchase Accounting
The merger between FirstEnergy and GPU 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 were finalized in the fourth
quarter of 2002, 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. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," Penelec evaluates its
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in its
evaluations of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on Penelec's future evaluations of goodwill. As of March 31, 2003,
Penelec had recorded goodwill of approximately $898.1 million related to the
merger.
Regulatory Accounting
Penelec is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the costs that the regulatory
agencies determine it 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. As of March 31, 2003, Penelec's
regulatory assets totaled $544 million. Penelec 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. Penelec continually monitors its derivative contracts to determine if
Penelec's activities, expectations, intentions, assumptions and estimates remain
valid. As part of Penelec's normal operations, it 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 been
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 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
125
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, 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 and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on 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
2002 and 2001, plan assets have earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to
FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing
to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy
included the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
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 asset impairment
must be recognized in the financial statements. If impairment other than of a
temporary nature has occurred, Penelec would recognize a loss - calculated as
the difference between the carrying value and the estimated fair value of the
asset (discounted future net cash flows).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after
126
January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs
created before February 1, 2003 are subject to this interpretation's provisions
in the first interim or annual reporting period beginning after June 15, 2003
(Penelec's third quarter of 2003). The FASB also identified transitional
disclosure provisions for all financial statements issued after January 31,
2003.
Penelec currently has involvement with entities in connection with
the sale of preferred securities, which may fall within the scope of this
interpretation, and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. Penelec currently consolidates these entities and
believes it will continue to consolidate following the adoption of FIN 46.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS 133 for decisions made by the Derivative Implementation Group, as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for quarters
which began prior to June 15, 2003, which continue to be applied based on their
original effect dates. Penelec is currently assessing the new standard and has
not yet determined the impact on its financial statements.
127
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.
128
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-
------------
FirstEnergy filed ten reports on Form 8-K since December 31, 2002. A
report dated January 17, 2003 reported updated information related with efforts
to prepare Davis-Besse for a safe and reliable return to service and the updated
schedule for JCP&L rate proceedings. A report dated January 21, 2003 reported
that the Pennsylvania Supreme Court denied further appeals of the February 21,
2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the
Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU
merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and
Penelec and remanded the merger savings issue back to the PPUC. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information, the filing of a $2 billion
shelf registration with the SEC and the status of the JCP&L rate proceedings. A
report dated March 18, 2003 reported NJBPU audit results of JCP&L
restructuring-related deferrals. A report dated April 16, 2003 reported updated
Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's
divestiture of its Argentina operations through the abandonment of its
investment resulting in a second quarter 2003 charge to net income of $63
129
million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003
results and other updated information including Davis-Besse updated ready for
restart schedule. A report dated May 9, 2003 reported updated Davis-Besse
information and a JCP&L rate proceedings update. A report dated May 9, 2003
reported that FirstEnergy had amended its Form 10-K for the year ended December
31, 2002 for a change in classification of a $57.1 net of tax charge with no
effect on previously reported net income.
OE, Penn-
---------
None.
CEI
---
CEI filed six reports on Form 8-K since December 31, 2002. A report
dated January 17, 2003 reported updated information related with efforts to
prepare Davis-Besse for a safe and reliable return to service. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003
reported Davis-Besse information. A report dated May 1, 2003 reported an updated
Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported
updated Davis-Besse information.
TE
--
TE filed six reports on Form 8-K since December 31, 2002. A report
dated January 17, 2003 reported updated information related with efforts to
prepare Davis-Besse for a safe and reliable return to service. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003
reported Davis-Besse information. A report dated May 1, 2003 reported an updated
Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported
updated Davis-Besse information.
Met-Ed
------
Met-Ed filed two reports on Form 8-K since December 31, 2002. A
report dated January 21, 2003 reported that the Pennsylvania Supreme Court
denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court
decision, which effectively affirmed the Pennsylvania Public Utility
Commission's order approving the FirstEnergy and GPU merger, let stand the
Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded
the merger savings issue back to the PPUC. A report dated March 12, 2003
reported Met-Ed's unaudited financial information for the year ended December
31, 2002.
Penelec
-------
Penelec filed one report on Form 8-K since December 31, 2002. A
report dated January 21, 2003 reported that the Pennsylvania Supreme Court
denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court
decision, which effectively affirmed the Pennsylvania Public Utility
Commission's order approving the FirstEnergy and GPU merger, let stand the
Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded
the merger savings issue back to the PPUC.
JCP&L
-----
JCP&L filed four reports on Form 8-K since December 31, 2002. A
report dated January 17, 2003 reported the updated schedule for JCP&L rate
proceedings. A report dated March 17, 2003 reported the status of the JCP&L rate
proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L
restructuring-related deferrals. A report dated May 9, 2003 reported a JCP&L
rate proceedings update.
130
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.
May 13, 2003
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
131
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 each registrant as of, and for, the periods presented in this
quarterly report;
4. Each 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 such registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to such 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 such 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. Each registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to such registrant's auditors and the audit
committee of such 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 such registrant's ability to
record, process, summarize and report financial data and have
identified for such 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 such registrant's internal
controls; and
6. Each 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: May 9, 2003
/s/H. Peter Burg
---------------------------
H. Peter Burg
Chief Executive Officer
132
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: May 9, 2003
/s/Earl T. Carey
--------------------------
Earl T. Carey
Chief Executive Officer
133
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 each registrant as of, and for, the periods presented in this
quarterly report;
4. Each 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 such registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to such 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 such 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. Each registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to such registrant's auditors and the audit
committee of such 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 such registrant's ability to
record, process, summarize and report financial data and have
identified for such 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 such registrant's internal
controls; and
6. Each 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: May 9, 2003
/s/Richard H. Marsh
---------------------------------
Richard H. Marsh
Chief Financial Officer
134