UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(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, 2004
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 ( ) FirstEnergy Corp.
Yes ( ) No (X ) 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
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 7, 2004
----- -----------------
FirstEnergy Corp., $.10 par value 329,836,276
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 Corp.
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,
replacement power costs being higher than anticipated or inadequately hedged,
maintenance costs being higher than anticipated, legislative and regulatory
changes (including revised environmental requirements), adverse regulatory or
legal decisions and the outcome of governmental investigations (including
revocation of necessary licenses or operating permits), availability and cost of
capital, the continuing availability and operation of generating units, the
inability to accomplish or realize anticipated benefits of strategic goals, the
ability to improve electric commodity margins and to experience growth in the
distribution business, the ability to access the public securities markets,
further investigation into the causes of the August 14, 2003, regional power
outage and the outcome, cost and other effects of present and potential legal
and administrative proceedings and claims related to that outage, a denial of or
material change to FirstEnergy's Application related to its Rate Stabilization
Plan, the risks and other factors discussed from time to time in the
registrants' Securities and Exchange Commission filings, including their annual
report on Form 10-K for the year ended December 31, 2003 and other similar
factors. The registrants expressly disclaim any current intention to update any
forward-looking statements contained in this document as a result of new
information, future events, or otherwise.
TABLE OF CONTENTS
Pages
Glossary of Terms......................................... i - ii
Part I. Financial Information
Items 1 and 2 Financial Statements and Management's
Discussion and Analysis of Results of Operation
and Financial Condition
Notes to Consolidated Financial Statements................ 1-19
FirstEnergy Corp.
Consolidated Statements of Income......................... 20
Consolidated Balance Sheets............................... 21
Consolidated Statements of Cash Flows..................... 22
Report of Independent Accountants......................... 23
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 24-48
Ohio Edison Company
Consolidated Statements of Income......................... 49
Consolidated Balance Sheets............................... 50
Consolidated Statements of Cash Flows..................... 51
Report of Independent Accountants......................... 52
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 53-62
The Cleveland Electric Illuminating Company
Consolidated Statements of Income......................... 63
Consolidated Balance Sheets............................... 64
Consolidated Statements of Cash Flows..................... 65
Report of Independent Accountants......................... 66
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 67-76
The Toledo Edison Company
Consolidated Statements of Income......................... 77
Consolidated Balance Sheets............................... 78
Consolidated Statements of Cash Flows..................... 79
Report of Independent Accountants......................... 80
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 81-90
Pennsylvania Power Company
Consolidated Statements of Income......................... 91
Consolidated Balance Sheets............................... 92
Consolidated Statements of Cash Flows..................... 93
Report of Independent Accountants......................... 94
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 95-101
TABLE OF CONTENTS (Cont'd)
Pages
Jersey Central Power & Light Company
Consolidated Statements of Income......................... 102
Consolidated Balance Sheets............................... 103
Consolidated Statements of Cash Flows..................... 104
Report of Independent Accountants......................... 105
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 106-114
Metropolitan Edison Company
Consolidated Statements of Income......................... 115
Consolidated Balance Sheets............................... 116
Consolidated Statements of Cash Flows..................... 117
Report of Independent Accountants......................... 118
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 119-127
Pennsylvania Electric Company
Consolidated Statements of Income......................... 128
Consolidated Balance Sheets............................... 129
Consolidated Statements of Cash Flows..................... 130
Report of Independent Accountants......................... 131
Management's Discussion and Analysis of Results
of Operations and Financial Condition................... 132-141
Item 3. Quantitative and Qualitative Disclosure
About Market Risk................................ 142
Item 4. Controls and Procedures............................ 142
Part II Other Information
Item 1. Legal Proceedings.................................. 143
Item 6. Exhibits and Reports on Form 8-K................... 143
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to
identify FirstEnergy Corp. and its subsidiaries:
ATSI.....................American Transmission Systems, Inc., owns and operates
transmission facilities
Avon.....................Avon Energy Partners Holdings
CEI......................The Cleveland Electric Illuminating Company, an Ohio
electric utility operating subsidiary
CFC......................Centerior Funding Corporation, a wholly owned finance
subsidiary of CEI
Emdersa................ Empresa Distribuidora Electrica Regional S.A
EUOC.....................Electric Utility Operating Companies, (OE, CEI, TE,
Penn, JCP&L, Met-Ed, Penelec, ATSI)
FENOC....................FirstEnergy Nuclear Operating Company, operates nuclear
generating facilities
FES......................FirstEnergy Solutions Corp., provides energy-related
products and services
FESC.....................FirstEnergy Service Company, provides legal, financial,
and other corporate support services
FGCO.....................FirstEnergy Generation Corp., operates nonnuclear
generating facilities
FirstCom.................First Communications, LLC, provides local and long-
distance phone service
FirstEnergy..............FirstEnergy Corp., a registered public utility holding
company
FSG......................FirstEnergy Facilities Services Group, LLC, the parent
company of several heating, ventilation air
conditioning and energy management companies
GLEP.....................Great Lakes Energy Partners, LLC, an oil and natural
gas exploration and production venture
GPU......................GPU, Inc., former parent of Jersey Central Power &
Light Copany, Metropolitan Edison Company and
Pennsylvania Electric Company, which merged with
FirstEnergy on November 7, 2001
GPU Capital..............GPU Capital, Inc., owned and operated electric
distribution systems in foreign countries
GPU Power................GPU Power, Inc., owned and operated generation
facilities in foreign countries
GPUS.....................GPU Service Company, previously provided corporate
support services
JCP&L....................Jersey Central Power & Light Company, a New Jersey
electric utility operating subsidiary
JCP&L Transition.........JCP&L Transition Funding LLC, a Delaware limited
liability company and issuer of transition bonds
MARBEL...................MARBEL Energy Corporation, holds FirstEnergy's interest
in Great Lakes Energy Partners, LLC
Met-Ed...................Metropolitan Edison Company, a Pennsylvania electric
utility operating subsidiary
MYR......................MYR Group, Inc., a utility infrastructure construction
service company
NEO......................Northeast Ohio Natural Gas Corp., a MARBEL subsidiary
OE.......................Ohio Edison Company, an Ohio electric utility operating
subsidiary
OE Companies.............OE and Pennsylvania Power Company
Penelec..................Pennsylvania Electric Company, a Pennsylvania electric
utility operating subsidiary
Penn.....................Pennsylvania Power Company, a Pennsylvania electric
utility operating subsidiary
PNBV.....................PNBV Capital Trust, a special purpose entity created
by OE in 1996
Shippingport.............Shippingport Capital Trust, a special purpose entity
created by CEI and TE in 1997
The following abbreviations and acronyms are used to identify frequently
used terms in this report:
TE.......................The Toledo Edison Company, an Ohio electric utility
operating subsidiary
TECC.....................Toledo Edison Capital Corporation, a 90% owned
subsidiary of TE
ALJ......................Administrative Law Judge
AOCL.....................Accumulated Other Comprehensive Loss
APB......................Accounting Principles Board
APB 25...................APB No. 25, "Accounting for Stock Issued to Employees"
ARO......................Asset Retirement Obligation
BGS......................Basic Generation Service
CO2......................Carbon Dioxide
CTC......................Competitive Transition Charge
ECAR.....................East Central Area Reliability Agreement
EITF.....................Emerging Issues Task Force
EITF 03-6................EITF Issue No. 03-6, "Participating Securities and the
Two-Class Method Under Financial
Accounting Standards Board Statement No. 128, Earnings
per Share"
EITF 99-19...............EITF Issue No. 99-19, "Reporting Revenue Gross as a
Principal versus Net as an Agent"
EPA......................Environmental Protection Agency
FASB.....................Financial Accounting Standards Board
FASB Concepts No. 7......FASB Concepts Statement No. 7, "Using Cash Flow
Information and Present Value in
Accounting Measurements"
FERC.....................Federal Energy Regulatory Commission
FIN .....................FASB Interpretation
FIN 46R..................FIN 46 (revised December 2003), "Consolidation of
Variable Interest Entities"
FSP......................FASB Staff Position
i
FSP 106-1................FASB Staff Position 106-1, "Accounting and Disclosure
Requirements Related to the Medicare"
Prescription Drug, Improvement and Modernization Act
of 2003"
GAAP.....................Accounting Principles Generally Accepted in the
United States
IRS......................Internal Revenue Service
ISO......................Independent System Operator
KWH......................Kilowatt-hours
LOC......................Letter of Credit
Medicare Act.............Medicare Prescription Drug, Improvement and
Modernization Act of 2003
MISO.....................Midwest Independent System Operator, Inc.
Moody's..................Moody's Investors Service
MTC......................Market Transition Charge
MW.......................Megawatts
NAAQS....................National Ambient Air Quality Standards
NERC.....................North American Electric Reliability Council
NJBPU....................New Jersey Board of Public Utilities
NOX......................Nitrogen Oxides
NRC......................Nuclear Regulatory Commission
NUG......................Non-Utility Generation
OCI......................Other Comprehensive Income
OPEB.....................Other Post-Employment Benefits
PJM......................PJM Interconnection ISO
PLR......................Provider of Last Resort
PPUC.....................Pennsylvania Public Utility Commission
PRP......................Potentially Responsible Party
PUCO.....................Public Utilities Commission of Ohio
S&P......................Standard & Poor's
SBC......................Societal Benefits Charge
SEC......................Securities and Exchange Commission
SFAS.....................Statement of Financial Accounting Standards
SFAS 71..................SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation"
SFAS 87..................SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 106.................SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS 123.................SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS 133.................SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities"
SFAS 140.................SFAS No. 140, "Accounting for Transfers and Servicing
of Financial Assets and Extinguishment of Liabilities"
SFAS 142.................SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143.................SFAS No. 143, "Accounting for Asset Retirement
Obligations"
SFAS 144.................SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets"
SFAS 150.................SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both
Liabilities and Equity"
SO2......................Sulfur Dioxide
SPE......................Special Purpose Entity
TBC......................Transition Bond Charge
TEBSA....................Termobarranquilla S.A., Empresa de Servicios Publicos
TMI-2....................Three Mile Island Unit 2
VIE......................Variable Interest Entity
ii
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 AND SUBSIDIARY
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1 - ORGANIZATION AND BASIS OF PRESENTATION:
The principal business of FirstEnergy is the holding, directly or
indirectly, of all of the outstanding common stock of its eight principal
electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed
and 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, 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: FENOC, FES and its subsidiary FGCO, FESC, FirstCom, FSG, GPU
Capital, GPU Power, MARBEL and MYR.
The Companies follow the accounting policies and practices prescribed
by the SEC, PUCO, PPUC, NJBPU and FERC. The condensed consolidated 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. Certain prior year
amounts have been reclassified to conform with the current year presentation. In
particular, expenses (including transmission and congestion charges) were
reclassified among purchased power, other operating costs and depreciation and
amortization to conform with the current year presentation of generation
commodity costs. In addition, revenues, expenses and taxes related to certain
divestitures in 2003 have been reclassified and reported net in discontinued
operations (see Note 2).
These statements should be read in conjunction with the financial
statements and notes included in the combined Annual Report on Form 10-K for the
year ended December 31, 2003 for FirstEnergy and the Companies. The preparation
of financial statements in conformity with GAAP requires management to make
periodic estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and disclosure of contingent assets and
liabilities. Actual results could differ from those estimates. The reported
results of operations are not indicative of results of operations for any future
period.
FirstEnergy's and the Companies' independent accountants have
performed reviews of, and issued reports on, these consolidated interim
financial statements in accordance with standards established by the American
Institute of Certified Public Accountants. Pursuant to Rule 436(c) under the
Securities Act of 1933, their reports of those reviews should not be considered
a report within the meaning of Section 7 and 11 of that Act, and the independent
accountant's liability under Section 11 does not extend to them.
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Consolidation
FirstEnergy and its subsidiaries consolidate all majority-owned
subsidiaries over which they exercise control and, when applicable, entities for
which they have a controlling financial interest and VIE's for which FirstEnergy
or any of its subsidiaries is the primary beneficiary. Intercompany transactions
and balances are eliminated in consolidation. Investments in nonconsolidated
affiliates (20-50 percent owned companies, joint ventures and partnerships) over
which FirstEnergy and its subsidiaries have the ability to exercise significant
influence, but not control, are accounted for on the equity basis.
1
FIN 46R addresses the consolidation of VIEs, including SPEs, that are
not controlled through voting interests or in which the equity investors do not
bear the residual economic risks and rewards. The first step under FIN 46R is to
determine whether an entity is within the scope of FIN 46R which occurs if it is
deemed to be a VIE. FirstEnergy and its subsidiaries consolidate those VIEs for
which they have determined that they are the primary beneficiary as defined by
FIN 46R. The provisions of FIN 46R were effective immediately for transactions
entered into subsequent to January 31, 2003 and became effective no later than
December 31, 2003 for entities that were considered SPEs under previous
guidance, and no later than March 31, 2004 for all other entities. See Variable
Interest Entities below.
Variable Interest Entities
Included in FirstEnergy's consolidated financial statements are PNBV
and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance
debt in connection with sale and leaseback transactions. PNBV and Shippingport
financial data are included in the consolidated financial statements of OE and
CEI, respectively.
PNBV was established to purchase a portion of the lease obligation
bonds issued with OE's 1987 sale and leaseback transactions involving its
interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and
available funds to purchase the notes issued by PNBV. Ownership of PNBV includes
a three-percent equity interest by a nonaffiliated third party and a
three-percent equity interest held by OES Ventures, a wholly owned subsidiary of
OE. Consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed
the trust investment of $361 million to an investment in collateralized lease
bonds of $372 million. The $11 million increase represented the minority
interest in the total assets of PNBV.
Shippingport was established to purchase all of the lease obligation
bonds issued by the owner trusts in CEI's and TE's Bruce Mansfield Plant sale
and leaseback transaction in 1987. CEI and TE acquired all of the notes issued
by Shippingport. Consolidation of this entity had no impact on the financial
statements of FirstEnergy. Prior to the adoption of FIN 46R, the assets and
liabilities of Shippingport were included on a proportionate basis in the
financial statements of CEI and TE. Adoption of FIN 46R resulted in the
consolidation of Shippingport by CEI as of December 31, 2003. Shippingport's
note payable to TE of $199 million ($10 million current) and $208 million ($9
million current) as of March 31, 2004 and December 31, 2003, respectively, is
included in long-term debt on CEI's Consolidated Balance Sheets.
Through its investment in PNBV, OE has, and through their investments
in Shippingport, CEI and TE have, variable interests in certain owner trusts
that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the
case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE.
FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of
the relevant owner trusts and were therefore not required to consolidate these
entities. The leases are accounted for as operating leases in accordance with
GAAP. The combined purchase price of $3.1 billion for all of the interests
acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and
equity of $600 million.
Each of OE, CEI and TE are exposed to losses under the applicable
sale-leaseback agreements upon the occurrence of certain contingent events that
each company considers unlikely to occur. OE, CEI and TE each have a maximum
exposure to loss of approximately $1 billion, which represents the net amount of
casualty value payments upon the occurrence of specified casualty events that
render the applicable plant worthless. Under the applicable sale - leaseback
agreements, OE, CEI and TE have net minimum discounted lease payments of $706
million, $109 million and $595 million, respectively, that would not be payable
if the casualty value payments are made. As of March 31, 2004, CEI and TE have
recorded above-market lease obligations related to the Bruce Mansfield Plant and
Beaver Valley Unit 2 totaling $1.1 billion (CEI - $774 million and TE - $311
million), of which $85 million (CEI - $60 million and TE - $25 million) is
current.
CEI formed a wholly owned statutory business trust to sell preferred
securities and invest the gross proceeds in 9% subordinated debentures of CEI.
The sole assets of the trust are the subordinated debentures with an aggregate
principal amount of $103 million. The trust's preferred securities are
redeemable at 100% of their principal amount at CEI's option beginning in
December 2006. CEI has effectively provided a full and unconditional guarantee
of the trust's obligations under the preferred securities.
Met-Ed and Penelec each formed statutory business trusts for
substantially similar transactions to those of CEI. However, ownership of the
respective Met-Ed and Penelec trusts is through separate wholly owned limited
partnerships. The sole assets 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 million each) of
Met-Ed and Penelec, respectively. The trust's preferred securities are
redeemable at 100% of their principal amount at the option of Met-Ed and Penelec
beginning in May 2004 and September 2004, respectively. In each case, Met-Ed and
Penelec have effectively provided a full and unconditional guarantee of
obligations under the trust's preferred securities. Met-Ed has provided notice
to holders of the trust preferred securities that it intends to redeem such
securities in May 2004.
2
Upon adoption of FIN 46R, the limited partnerships and statutory
business trusts discussed above were no longer consolidated on the financial
statements of FirstEnergy or, as applicable, CEI, Met-Ed or Penelec. As of
December 31, 2003 and March 31, 2004, subordinated debentures held by the
affiliated trusts were included in long-term debt of the applicable company and
equity investments in the trusts were included in other investments.
For the quarter ended March 31, 2004, FirstEnergy evaluated, among
other entities, its power purchase agreements and determined that certain NUG
entities may be VIEs to the extent they own a plant that sells substantially all
of its output to an EUOC and the contract price for power is correlated with the
plant's variable costs of production. FirstEnergy, through its subsidiaries
JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase
agreements with NUG entities. The agreements were structured pursuant to the
Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in
the creation of and has no equity or debt invested in these entities.
FirstEnergy has determined that for all but nine of these entities,
either JCP&L, Met-Ed or Penelec do not have variable interests in the entities
or the entities are governmental or not-for-profit organizations not within the
scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
remaining nine entities, which sell their output at variable prices that
correlate to some extent with the operating costs of the plants.
FirstEnergy has requested but not received the information necessary
to determine whether these nine entities are VIEs or whether JCP&L, Met-Ed or
Penelec is the primary beneficiary. In most cases, the requested information was
deemed to be competitive and proprietary data. As such, FirstEnergy applied the
scope exception that exempts enterprises unable to obtain the necessary
information to evaluate entities under FIN 46R. The maximum exposure to loss
from these entities results from increases in the variable pricing component
under the contract terms and cannot be determined without the requested data.
Purchased power costs from these entities during the first quarters of 2004 and
2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec -
$7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and
Penelec - $7 million), respectively. FirstEnergy is required to continue to make
exhaustive efforts to obtain the necessary information in future periods and is
unable to determine the possible impact of consolidating any such entity without
this information.
Earnings Per Share
Basic earnings per share are computed using the weighted average of
actual common shares outstanding as the denominator. Diluted earnings per share
reflect the weighted average of actual common shares outstanding plus the
potential additional common shares that could result if dilutive securities and
agreements were exercised in the denominator. In the first quarter of 2004 and
2003, stock-based awards to purchase shares of common stock totaling 3.3 million
and 3.6 million, respectively, were excluded from the calculation of diluted
earnings per share of common stock because their exercise prices were greater
than the average market price of common shares during the period. The following
table reconciles the denominators for basic and diluted earnings per share from
Income before Discontinued Operations and Cumulative Effect of Accounting
Change:
Three Months Ended
March 31,
Reconciliation of Basic and --------------------
Diluted Earnings per Share 2004 2003
---------------------------------------------------------------------------
(In thousands)
Income before discontinued operations and
cumulative effect of accounting change............ $173,999 $114,380
Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share
(weighted average shares actually outstanding)... 327,057 293,886
Assumed exercise of dilutive stock options
and awards....................................... 1,977 991
Denominator for diluted earnings per share.......... 329,034 294,877
===========================================================================
Income before Discontinued Operations and Cumulative
Effect of Accounting Change, per common share:
Basic............................................. $0.53 $0.39
Diluted........................................... $0.53 $0.39
---------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption
Long-term debt includes the preferred stock of consolidated
subsidiaries subject to mandatory redemption as of March 31, 2004 and December
31, 2003 in accordance with SFAS 150. This standard, issued in May 2003,
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity;
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. The adoption of SFAS 150 effective
July 1, 2003 had no impact on FirstEnergy's Consolidated Statements of Income
because the preferred dividends were previously included in net interest charges
and required no reclassification. CEI and Penn, however, did not include the
3
preferred dividends on their manditorily redeemable preferred stock in interest
expense for the quarter ended March 31, 2003, but have included the dividends in
interest charges for the quarter ended March 31, 2004.
Securitized Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include
the financial statements of JCP&L Transition, a wholly owned limited liability
company of JCP&L. In June 2002, JCP&L Transition 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 did not purchase and does not own any of the transition bonds,
which are included as long-term debt on each of FirstEnergy's and JCP&L's
Consolidated Balance Sheets. The transition bonds represent obligations only of
JCP&L Transition and are collateralized solely by the equity and assets of JCP&L
Transition, which consist primarily of bondable transition property. The
bondable transition property is solely the property of JCP&L Transition.
Bondable transition property represents the irrevocable right under
New Jersey law of a utility company to charge, collect and receive from its
customers, through a non-bypassable TBC, the principal amount and interest on
the transition bonds and other fees and expenses associated with their issuance.
JCP&L sold the bondable transition property to JCP&L Transition and, as
servicer, manages and administers the bondable transition property, including
the billing, collection and remittance of the TBC, pursuant to a servicing
agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee
of $100,000 that is payable from TBC collections.
Derivative Accounting
FirstEnergy is exposed to financial risks resulting from fluctuating
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, the ineffective portion of hedge gains and losses is
included in net income.
In 2001, FirstEnergy entered into interest rate derivative
transactions 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 are 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
net deferred loss included in AOCL as of March 31, 2004 and December 31, 2003
was $111 million. Approximately $6 million (after tax) of the net deferred loss
on derivative instruments in AOCL as of March 31, 2004, is expected to be
reclassified to earnings during the next twelve months as hedged transactions
occur. The fair value of these derivative instruments will fluctuate from period
to period based on various market factors.
During the first quarter of 2004, FirstEnergy executed
fixed-for-floating interest rate swap agreements with an aggregate notional
amount of $200 million, whereby FirstEnergy receives fixed cash flows based on
the fixed coupons of the hedged securities and pays variable cash flows based on
short-term variable market interest rates. 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, fixed interest rates received,
and interest payment dates match those of the underlying debt obligations.
FirstEnergy entered into interest rate swap agreements on $200 million notional
amount of its subsidiaries' senior notes and subordinated debentures having a
weighted average fixed interest rate of 5.73%; the interest rate swap agreements
have effectively converted that rate to a current weighted average variable rate
of 2.33%. The notional values of interest rate swap agreements increased to
$1.35 billion as of March 31, 2004 from $1.15 billion as of December 31, 2003.
Goodwill
In a business combination, the excess of the purchase price over the
estimated fair values of assets acquired and liabilities assumed is recognized
as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates
4
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), the goodwill is tested for impairment. If
an impairment is indicated, FirstEnergy recognizes a loss - calculated as the
difference between the implied fair value of a reporting unit's goodwill and the
carrying value of the goodwill.
As of March 31, 2004, FirstEnergy had $6.1 billion of goodwill that
primarily relates to its regulated services segment. In the first quarter of
2004, FirstEnergy adjusted goodwill for interest received on a pre-merger income
tax refund related to the former GPU companies. A summary of the changes in
FirstEnergy's goodwill for the three months ended March 31, 2004 is shown below:
(In millions)
------------------------------------------------------
Balance as of December 31, 2003 ........ $6,128
GPU acquisition......................... (11)
------
Balance as of March 31, 2004............ $6,117
======
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, 2004, FirstEnergy's AOCL was approximately $344 million as compared to
the December 31, 2003 balance of $353 million. A reconciliation of net income to
comprehensive income for the three months ended March 31, 2004 and 2003, is
shown below:
Three Months Ended
March 31,
-------------------
2004 2003
---- ----
(In thousands)
Net income............................. $173,999 $218,502
Other comprehensive income, net of tax:
Change in fair value of hedge transactions (393) 4,341
Unrealized gains on available for sale securities 9,215 1,484
-------- --------
Comprehensive income................... $182,821 $224,327
======== ========
Asset Retirement Obligations
FirstEnergy recognizes a liability for retirement obligations
associated with tangible assets in accordance with SFAS 143. The Companies
recognize a regulatory asset or liability when the criteria for such treatment
are met. FirstEnergy has identified applicable legal obligations as defined
under the 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. The ARO liability was $1.198 billion as of March 31,
2004 and included $1.185 billion for nuclear decommissioning of the Beaver
Valley, Davis-Besse, Perry, and TMI-2 nuclear generating facilities. The
Companies' share of the obligation to decommission these units was developed
based on site specific studies performed by an independent engineer. FirstEnergy
utilized an expected cash flow approach (as discussed in FASB Concepts No. 7) to
measure the fair value of the nuclear decommissioning ARO. The Companies
maintain nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of March 31, 2004, the
fair value of the decommissioning trust assets was $1.420 billion. Under the
current terms of the plants' operating licenses, payments for decommissioning of
the nuclear generating units would begin in 2014, when actual decommissioning
work would begin.
The following table provides the beginning and ending aggregate
carrying amount of the total ARO and the changes to the balance during the first
quarter of 2004.
ARO Reconciliation 2004
----------------------------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2004 ...................... $1,179
Liabilities incurred.......................................... --
Liabilities settled........................................... --
Accretion in 2004............................................. 19
Revisions in estimated cash flows............................. --
------------------------------------------------------------------------
Ending balance as of March 31, 2004........................... $1,198
------------------------------------------------------------------------
5
Stock-Based Compensation
FirstEnergy applies the recognition and measurement principles of APB
25 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.
In March 2004, the FASB issued an exposure draft of a proposed
standard that, if adopted, will change the accounting for employee stock options
and other equity-based compensation. The proposed standard would require
companies to expense the fair value of stock options on the grant date and would
be effective for the Companies on January 1, 2005. FirstEnergy will evaluate the
requirements of the final standard, expected by late 2004, to determine the
impact on its results of operations.
If FirstEnergy had accounted for employee stock options under the fair
value method, as provided under SFAS 123, 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 reductions to net income and earnings
per share. The following table summarizes those effects.
Three Months Ended
March 31,
------------------
2004 2003
---- ----
(In thousands)
Net income, as reported................... $173,999 $218,502
Add back stock-based compensation
expense reported in net income, net of tax
(based on APB 25)....................... -- 43
Deduct stock-based compensation expense
based upon estimated fair value, net of tax (4,404) (2,983)
---------------------------------------------------------------------
Adjusted net income....................... $169,595 $215,562
---------------------------------------------------------------------
Earnings Per Share of Common Stock -
Basic
As Reported.......................... $0.53 $0.74
Adjusted............................. $0.52 $0.73
Diluted
As Reported.......................... $0.53 $0.74
Adjusted............................. $0.52 $0.73
Discontinued Operations
FirstEnergy's discontinued operations in the first quarter of 2003
consisted of the net results aggregating $2 million from its Argentina and
Bolivia international businesses and certain domestic operations divested in
2003. The related revenues, expenses and taxes were reclassified from the
previously reported Consolidated Statement of Income for the quarter ended March
31, 2003 and netted in Discontinued Operations. In April 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. FirstEnergy sold its Bolivia operations,
Empresa Guaracachi S.A., in December 2003. Domestic operations sold in 2003
consisted of three former FSG subsidiaries and the MARBEL subsidiary, NEO.
Cumulative Effect of Accounting Change
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 on the date of adoption was $1.11 billion, including
accumulated accretion for the period from the date the liability was incurred to
the date of adoption. The remaining cumulative effect adjustment for
unrecognized depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and the reversal of accumulated estimated removal
costs for non-regulated generation assets, was a $175 million increase to
income, $102 million net of tax, or $0.35 per share of common stock (basic and
diluted) in the quarter ended March 31, 2003.
6
Restatements of TE and JCP&L Previously Reported Quarterly Results
Earnings for the first quarter of 2003 have been restated for TE and
JCP&L to reflect adjustments to costs that were subsequently capitalized to
construction projects. The results for TE have also been restated to correct the
amount reported for interest expense. TE's costs which were originally recorded
as operating expenses and were subsequently capitalized to construction were
$0.4 million ($0.2 million after-tax) in the first quarter of 2003. TE's
interest expense was overstated by $0.9 million ($0.5 million after-tax) in the
first quarter of 2003. Similar to TE, JCP&L's capital costs originally recorded
as operating expenses were $0.2 million ($0.1 million after-tax) in the first
quarter of 2003. The impact of these adjustments was not material to the
consolidated balance sheets or consolidated statements of cash flows for TE and
JCP&L for any quarter of 2003.
The effects of these adjustments on the consolidated statements of
income previously reported for TE and JCP&L for the three months ended March 31,
2003, are as follows:
TE JCP&L
---------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- ----------- ------------- ------------
(In thousands)
Operating Revenues..........................$ 231,822 $ 231,822 $ 656,952 $ 656,952
Operating Expenses.......................... 226,345 226,501 581,744 581,609
----------- ------------ ---------- -----------
Operating Income............................ 5,477 5,321 75,208 75,343
Other income................................ 3,100 3,100 1,176 1,176
----------- ------------ ---------- -----------
Income before net interest charges.......... 8,577 8,421 76,384 76,519
Net interest charges........................ 9,977 9,050 22,502 22,502
----------- ------------ ---------- -----------
Income (loss) before cumulative effect
of accounting change..................... (1,400) (629) 53,882 54,017
Cumulative effect of accounting change...... 25,550 25,550 -- --
----------- ------------ ---------- -----------
Net income.................................. 24,150 24,921 53,882 54,017
Preferred stock dividend requirements....... 2,205 2,205 125 125
----------- ------------ ---------- -----------
Earnings attributable to
common stock.............................$ 21,945 $ 22,716 $ 53,757 $ 53,892
=========== ============ ========== ===========
3 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:
Capital Expenditures
FirstEnergy's current forecast reflects expenditures of approximately
$2.3 billion (OE-$295 million, CEI-$275 million, TE-$141 million, Penn-$143
million, JCP&L-$446 million, Met-Ed-$168 million, Penelec-$198 million, ATSI-$66
million, FES-$443 million and other subsidiaries-$125 million) for property
additions and improvements from 2004-2006, of which approximately $720 million
(OE-$111 million, CEI-$95 million, TE-$49 million, Penn-$63 million, JCP&L-$150
million, Met-Ed-$55 million, Penelec-$65 million, ATSI-$23 million, FES-$71
million and other subsidiaries-$38 million) is applicable to 2004. Investments
for additional nuclear fuel during the 2004-2006 period are estimated to be
approximately $315 million (OE-$45 million, CEI-$62 million, TE-$44 million,
Penn-$35 million and FES-$129 million), of which approximately $86 million
(OE-$26 million, CEI-$27 million, TE-$12 million and Penn-$21 million) applies
to 2004.
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. As of March 31, 2004, outstanding guarantees and
other assurances aggregated $1.9 billion and included contract guarantees ($1
billion), surety bonds ($0.2 billion) and letters of credit ($.7 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 $1 billion (included in the $1.9
billion discussed above) as of March 31, 2004 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.
7
While guarantees are normally parental commitments for the future
payment of subsidiary obligations, subsequent to the occurrence of a credit
rating downgrade or "material adverse event" the immediate payment of cash
collateral or provision of an LOC may be required. The following table
summarizes collateral provisions as of March 31, 2004:
Collateral Paid
Total -------------------------- Remaining
Collateral Provisions Exposure Cash Letters of Credit Exposure(1)
- --------------------------------------------------------------------------------
(In millions)
Rating downgrade.......... $228 $133 $18 $ 77
Adverse event............. 232 -- 69 163
- ----------------------------------------------------------------------------
Total..................... $460 $133 $87 $240
============================================================================
(1) As of April 12, 2004, FirstEnergy's remaining exposure was $237
million, with $141 million of cash and $72 million of letters of
credit provided as collateral.
Most of FirstEnergy's surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees of $240 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.
FirstEnergy has also guaranteed the obligations of the operators of
the TEBSA project in Colombia, up to a maximum of $6 million (subject to
escalation) under the project's operations and maintenance agreement. In
connection with the sale of TEBSA in January 2004, the purchaser indemnified
FirstEnergy against any loss under this guarantee. FirstEnergy has provided the
TEBSA project lenders a $60 million letter of credit, which is renewable and
declines yearly based upon the senior outstanding debt of TEBSA. This letter of
credit granted FirstEnergy the ability to sell its remaining 20.1% interest in
Avon (parent of Midlands Electricity in the United Kingdom).
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. 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 that 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.
Overall, FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict future change in regulatory policies and
what, if any, the effects of such change would be. FirstEnergy estimates
additional capital expenditures for environmental compliance of approximately
$91 million for 2004 through 2006, which is included in the $2.3 billion of
forecasted capital expenditures for 2004 through 2006. Additional estimated
capital expenditures of $481 million relating to proposed environmental laws
could be required after 2006.
Clean Air Act Compliance
The Companies are required to meet federally approved 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 EPA has an interim enforcement policy for SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. The Companies cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy.
The Companies are complying with SO2 reduction requirements under the
Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions required by the 1990 Amendments 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' 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the District
of Columbia based on a conclusion that such NOx emissions are contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. New
Jersey and Pennsylvania submitted a SIP that required compliance with the NOx
budgets at the Companies' New Jersey and Pennsylvania facilities by May 1, 2003.
Michigan and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Michigan and Ohio facilities by May 31, 2004. The Companies'
facilities have complied with the NOx budgets in 2003 and 2004, respectively.
8
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and
proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA
proposed the "Interstate Air Quality Rule" covering a total of 29 states
(including New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on proposed findings that air pollution emissions from 29 eastern states and the
District of Columbia significantly contribute to nonattainment of the NAAQS for
fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has
proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and SO2
emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the
EPA, SO2 emissions would be reduced by approximately 3.6 million tons in 2010,
across states covered by the rule, with reductions ultimately reaching more than
5.5 million tons annually. NOx emission reductions would measure about 1.5
million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance
with these proposed regulations may be substantial and will depend on whether
and how they are ultimately implemented by the states in which the Companies
operate affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants, identifying mercury as the hazardous air pollutant of greatest
concern. On December 15, 2003, the EPA proposed two different approaches to
reduce mercury emissions from coal-fired power plants. The first approach would
require plants to install controls known as "maximum achievable control
technologies" (MACT) based on the type of coal burned. According to the EPA, if
implemented, the MACT proposal would reduce nationwide mercury emissions from
coal-fired power plants by 14 tons to approximately 34 tons per year. The second
approach proposes a cap-and-trade program that would reduce mercury emissions in
two distinct phases. Initially, mercury emissions would be reduced by 2010 as a
"co-benefit" from implementation of SO2 and NOx emission caps under the EPA's
proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade
program would be implemented in 2018 to cap nationwide mercury emissions from
coal-fired power plants at 15 tons per year. The EPA has agreed to choose
between these two options and issue a final rule by March 15, 2005. The future
cost of compliance with these regulations may be substantial.
W. H. Sammis Plant
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, which is owned by OE and Penn. In addition, the U.S. Department of
Justice filed eight civil complaints against various investor-owned utilities,
which included a complaint against OE and Penn in the U.S. District Court for
the Southern District of Ohio. The NOV and complaint allege violations of the
Clean Air Act based on operation and maintenance of the W. H. 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. On August 7, 2003, the United
States District Court for the Southern District of Ohio ruled that 11 projects
undertaken at the W. H. Sammis Plant between 1984 and 1998 required
pre-construction permits under the Clean Air Act. The ruling concludes the
liability phase of the case, which deals with applicability of Prevention of
Significant Deterioration provisions of the Clean Air Act. The remedy phase,
which is currently scheduled to be ready for trial beginning July 19, 2004, will
address civil penalties and what, if any, actions should be taken to further
reduce emissions at the plant. In the ruling, the Court indicated that the
remedies it "may consider and impose involved a much broader, equitable
analysis, requiring the Court to consider air quality, public health, economic
impact, and employment consequences. The Court may also consider the less than
consistent efforts of the EPA to apply and further enforce the Clean Air Act."
The potential penalties that may be imposed, as well as the capital expenditures
necessary to comply with substantive remedial measures that may be required,
could have a material adverse impact on FirstEnergy's financial condition and
results of operations. Management is unable to predict the ultimate outcome of
this matter and no liability has been accrued as of March 31, 2004.
Regulation of Hazardous Waste
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 subsequently determined 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 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, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheet as of March 31, 2004, based on estimates of the total
9
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 SBC. Included in Current Liabilities and Other Noncurrent
Liabilities are accrued liabilities aggregating approximately $65 million (JCP&L
- - $45.5 million, CEI - $2.4 million, TE - $0.2 million, Met-Ed - $0.05 million,
Penelec - $0.02 million, and other - $16.8 million) as of March 31, 2004. The
Companies accrue environmental liabilities only when they can conclude that it
is probable that they have an obligation for such costs and can reasonably
determine the amount of such costs. Unasserted claims are reflected in the
Companies' determination of environmental liabilities and are accrued in the
period that they are both probable and reasonably estimable.
Climate Change
In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but it failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.
The Companies cannot currently estimate the financial impact of
climate change policies although the potential restrictions on CO2 emissions
could require significant capital and other expenditures. However, the CO2
emissions per kilowatt-hour of electricity generated by the Companies is lower
than many regional competitors due to the Companies' diversified generation
sources which includes low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the
result of the federal Clean Water Act and its amendments, apply to the
Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water
quality standards applicable to the Companies' operations. As provided in the
Clean Water Act, authority to grant federal National Pollutant Discharge
Elimination System water discharge permits can be assumed by a state. Ohio, New
Jersey and Pennsylvania have assumed such authority.
Power Outages
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L's territory. In an investigation into the
causes of the outages and the reliability of the transmission and distribution
systems of all four New Jersey electric utilities, the NJBPU concluded that
there was not a prima facie case demonstrating that, overall, JCP&L provided
unsafe, inadequate or improper service to its customers. Two class action
lawsuits (subsequently consolidated into a single proceeding) were filed in New
Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies,
seeking compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
Since July 1999, this litigation has involved a substantial amount of
legal discovery including interrogatories, request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L employees. In addition, there have been many motions filed and
argued by the parties involving issues such as the primary jurisdiction and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate Division determined that the trial court has proper jurisdiction
over this litigation. In August 2002, the trial court granted partial summary
judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, and strict products liability. In
November 2003, the trial court granted JCP&L's motion to decertify the class and
denied plaintiffs' motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings have been appealed to the Appellation Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of March 31, 2004.
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
10
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Regulatory Matters below). As many of these initiatives already
were in process and budgeted in 2004, FirstEnergy does not believe that any
incremental expenses associated with additional initiatives undertaken during
2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures. FirstEnergy has not accrued a
liability as of March 31, 2004 for any expenditures in excess of those actually
incurred through that date.
Davis-Besse
FENOC received a subpoena in late 2003 from a grand jury sitting in
the United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis-Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks among other things, suspension of the Davis-Besse operating
license. If it were ultimately determined that FirstEnergy has legal liability
or is otherwise made subject to enforcement action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on FirstEnergy's financial condition and results of operations.
Other Legal Matters
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant not otherwise discussed above are described below.
Legal proceedings have been filed against FirstEnergy in connection
with, among other things, the restatements in August 2003, by FirstEnergy and
its Ohio utility subsidiaries of previously reported results, the August 14th
power outage described above, and the extended outage at the Davis-Besse Nuclear
Power Station. Depending upon the particular proceeding, the issues raised
include alleged violations of federal securities laws, breaches of fiduciary
duties under state law by FirstEnergy directors and officers, and damages as a
result of one or more of the noted events. The securities cases have been
consolidated into one action pending in federal court in Akron, Ohio. The
derivative actions filed in federal court likewise have been consolidated as a
separate matter, also in federal court in Akron. There also are pending
derivative actions in state court.
FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two regulatory proceedings initiated at the PUCO in response to complaints
alleging failure to provide reasonable and adequate service stemming primarily
from the August 14th power outage. FirstEnergy is vigorously defending these
actions, but cannot predict the outcome of any of these proceedings or whether
any further regulatory proceedings or legal actions may be initiated against
them.
Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outage. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed.
If FirstEnergy were ultimately determined to have legal liability in
connection with the legal proceedings described above, it could have a material
adverse effect on its financial condition and results of operations.
11
4 - PENSION AND OTHER POSTRETIREMENT BENEFITS:
The components of net periodic pension and postretirement benefit cost
consisted of the following:
Pension Benefits Other Benefits
-------------------- ------------------
Three months ended Three months ended
March 31, March 31,
-------------------- ------------------
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------
(In millions)
Service cost ............................. $ 19 $ 17 $ 10 $ 11
Interest cost............................. 63 64 30 35
Expected return on plan assets............ (71) (63) (11) (11)
Transition obligation..................... -- -- -- 2
Amortization of prior service cost........ 2 2 (9) (2)
Recognized net actuarial loss............. 10 16 10 11
------ ------ ------ ------
Net periodic cost......................... $ 23 $ 36 $ 30 $ 46
====== ====== ====== ======
FirstEnergy contributed $16 million to its other postretirement
benefit plans in the first quarter of 2004 and has no funding requirements for
the remainder of 2004. FirstEnergy did not contribute to its pension plans
during the first quarter of 2004 and has no funding requirements for the
remainder of 2004. The net periodic pension cost in the three months ended March
31, 2004 and March 31, 2003 included $3 million and $5 million, respectively, of
costs capitalized. Similarly, the net periodic cost for other postretirement
costs in the three months ended March 31, 2004 and March 31, 2003 included $4
million and $5 million, respectively, of capital costs.
Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began
accounting for the effects of the Medicare Act effective January 1, 2004 because
of a plan amendment during the quarter, which required remeasurement of the
plan's obligations. Based on the guidance in proposed FSP 106-b issued in March
2004, FirstEnergy has calculated a reduction of $318 million in the accumulated
postretirement benefit obligation as a result of the federal subsidy provided
under the Medicare Act. The subsidy reduced net periodic costs during the first
quarter of 2004 by $10 million, which included increased amortization of the
actuarial experience loss of $0.8 million, reduction of $6.1 million in past
service cost, $1.1 million of current period service cost and $3.6 million of
interest cost. Specific authoritative guidance on the accounting for the federal
subsidy is pending, and when issued, could require a change to previously
reported information. In addition, the plan amendment announced in the first
quarter of 2004 reduced postretirement benefit costs during the quarter by $9.2
million as a result of increased cost-sharing by employees and retirees
effective January 1, 2005.
5 - INTERNATIONAL DIVESTITURES:
FirstEnergy completed the sale of its international assets during the
quarter ended March 31, 2004 with the sales of its remaining 20.1 percent
interest in Avon on January 16, 2004, and its 28.67 percent interest in TEBSA on
January 30, 2004. Impairment charges related to Avon and TEBSA were recorded in
the fourth quarter of 2003 and no gain or loss was recognized upon the sales in
2004. Avon, TEBSA and other international assets sold in 2003 were acquired as
part of FirstEnergy's November 2001 merger with GPU.
6 - REGULATORY MATTERS:
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation contain 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 PLR obligations to customers in the Companies'
service areas;
o allowing recovery of transition costs (sometimes referred to
as stranded investment);
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and transition costs recovery charges;
o deregulating the Companies' electric generation businesses;
o continuing regulation of the Companies' transmission and
distribution system; and
o requiring corporate separation of regulated and unregulated
business activities.
12
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26 and 27, 2004, certain FirstEnergy companies
participated in a NERC Control Area Readiness Audit. This audit, part of an
announced program by NERC to review control area operations throughout much of
the United States during 2004, is an independent review to identify areas for
improvement. The final audit report was completed on April 30, 2004. The report
identified positive observations and included various recommendations for
improvement. FirstEnergy is currently reviewing the audit results and
recommendations and expects to implement those relating to summer 2004 by June
30. Based on its review thus far, FirstEnergy believes that none of the
recommendations identify a need for any incremental material investment or
upgrades to existing equipment. FirstEnergy notes, however, that NERC or other
applicable government agencies and reliability coordinators may take a different
view as to recommended enhancements or may recommend additional enhancements in
the future that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
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 recovery period extension is related to the
customer shopping incentives recovery discussed below. 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 SFAS 71 to OE's generation
business and the nonnuclear generation businesses of CEI and TE was discontinued
with the issuance of the PUCO transition plan order, 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.
13
Also as part of the settlement agreement, FirstEnergy gives 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. Subject to approval by the PUCO, recovery will be
accomplished by extending the respective transition cost recovery period.
On October 21, 2003, the Ohio EUOC filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing the Ohio EUOC's
support of energy efficiency and economic development
efforts.
Under the first option, an auction would be conducted to secure
generation service for the Ohio EUOC's customers. Beginning in 2006, customers
would pay market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of the Ohio EUOC's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity if shopping drops below 20%. Under the proposed
plan, the Ohio EUOC are requesting:
o Extension of the transition cost amortization period for OE
from 2006 to 2007; for CEI from 2008 to mid-2009 and for TE
from mid-2007 to mid-2008;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
o Ability to initiate a request to increase generation rates
under certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. Oral arguments were held before
the PUCO on April 21 and a decision is expected from the PUCO in the Spring of
2004.
Transition Cost Amortization
OE, CEI and TE amortize transition costs (see Regulatory Matters -
Ohio) using the effective interest method. Under the Ohio transition plan, total
transition cost amortization is expected to approximate the following for 2004
through 2009.
(In millions)
---------------------------------------
2004...................... $794
2005...................... 922
2006...................... 371
2007...................... 208
2008...................... 164
2009...................... 46
---------------------------------------
14
The decrease in amortization beginning in 2006 results from the
termination of generation-related transition cost recovery under the Ohio
transition plan.
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 had been in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable SBC to recover costs which include nuclear
plant decommissioning and manufactured gas plant remediation, as well as a
non-bypassable 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 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 and there would be an adjustment to goodwill.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly
owned subsidiary, JCP&L Transition, $320 million of transition bonds (recognized
on the Consolidated Balance Sheet) which securitized the recovery of these costs
and which provided for a usage-based non-bypassable TBC and for the transfer of
the bondable transition property to another entity.
Prior to August 1, 2003, JCP&L's PLR obligation to provide BGS to
non-shopping customers was 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 NUG agreements exceed amounts collected
through BGS and MTC rates. As of March 31, 2004, the accumulated deferred cost
balance totaled approximately $425 million, after the charge discussed below.
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's two August 2002 rate
filings requested increases in base electric rates of approximately $98 million
annually and requested the recovery of 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. On July 25, 2003, the NJBPU announced its JCP&L base electric
rate proceeding decision, which reduced JCP&L's annual revenues by approximately
$62 million effective August 1, 2003. The NJBPU decision also provided for an
interim return on equity of 9.5% on JCP&L's rate base for six to twelve months.
During that period, JCP&L will initiate another proceeding to request recovery
of additional costs incurred to enhance system reliability. In that proceeding,
the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%,
depending on its assessment of the reliability of JCP&L's service. Any reduction
would be retroactive to August 1, 2003. The net revenue decrease from the
NJBPU's decision consists of a $223 million decrease in the electricity delivery
charge, a $111 million increase due to the August 1, 2003 expiration of annual
customer credits previously mandated by the New Jersey transition legislation, a
$49 million increase in the MTC tariff component, and a net $1 million increase
in the SBC. The MTC allows for the recovery of $465 million in deferred energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary settlement agreement between
certain parties. As a result, JCP&L recorded charges to net income for the year
ended December 31, 2003, aggregating $185 million ($109 million net of tax)
consisting of the $153 million of disallowed deferred energy costs and other
regulatory assets. JCP&L filed a motion for rehearing and reconsideration with
the NJBPU on August 15, 2003 with respect to the following issues: (1) the
disallowance of the $153 million deferred energy costs; (2) the reduced rate of
return on equity; and (3) $42.7 million of disallowed costs to achieve merger
savings. On October 10, 2003, the NJBPU held the motion in abeyance until the
final NJBPU decision and order which is expected to be issued in the second
quarter of 2004.
JCP&L's BGS obligation for the twelve month period beginning August 1,
2003 was auctioned in February 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. The
BGS auction for the subsequent period was completed in February 2004. The NJBPU
adjusted the generation component of JCP&L's retail rates on August 1, 2003 to
reflect the results of the BGS auction.
On April 28, 2004, the NJBPU directed JCP&L to file testimony by the
end of May 2004, either supporting a continuation of the current level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers,
or, alternatively, proposing a reduction, termination or capping of the funding.
JCP&L cannot predict the outcome of this matter.
15
Pennsylvania
The PPUC authorized in 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 and would be an adjustment to
goodwill.
In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate relief proceedings which
approved the FirstEnergy/GPU merger and provided PLR deferred accounting
treatment for energy costs, permitting Met-Ed and Penelec to defer, for future
recovery, energy costs in excess of amounts reflected in their capped generation
rates retroactive to January 1, 2001. This PLR deferral accounting procedure was
later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The
court decision also affirmed the PPUC decision regarding approval of the merger,
remanding the decision to the PPUC only with respect to the issue of merger
savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR
deferred energy costs which aggregated $287.1 million, reflecting the potential
adverse impact of the then pending Pennsylvania Supreme Court decision whether
to review the Commonwealth Court decision. As a result, FirstEnergy recorded in
2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to
income for the deferred costs incurred subsequent to the merger. The reserve for
the remaining $231.3 million of deferred costs increased goodwill by an
aggregate net of tax amount of $135.3 million.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed Met-Ed and
Penelec to file a position paper on the effect of the Commonwealth Court order
on the Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003,
voiding the Settlement Stipulation in its entirety and reinstating Met-Ed's and
Penelec's restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the CTC rates and shopping credits that were in effect prior to the
June 21, 2001 order to be effective upon one day's notice. In response to that
order, Met-Ed and Penelec filed these supplements to their tariffs to become
effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered accounting treatment regarding the CTC rate/shopping credit swap
should follow the ratemaking, and that the PPUC's findings would not impair
their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA
(an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and
Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed's
and Penelec's other clarification requests and granting ARIPPA's petition with
respect to the accounting treatment of the changes to the CTC rate/shopping
credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the
Commonwealth Court asking that the Court reverse the PPUC's finding that
requires Met-Ed and Penelec to treat the stipulated CTC rates that were in
effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, a Commonwealth Court judge issued an Order
denying Met-Ed's and Penelec's objection without explanation. Due to the
vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an
Application for Clarification with the judge. Concurrent with this filing,
Met-Ed and Penelec, in order to preserve their rights, also filed with the
Commonwealth Court both a Petition for Review of the PPUC's October 2 and
October 16 Orders, and an application for reargument, if the judge, in his
clarification order, indicates that Met-Ed's and Penelec's objection was
intended to be denied on the merits. In addition to these findings, Met-Ed and
Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly
reports for the twelve months ended December 31, 2001 and 2002, and for the
first two quarters of 2003, reflecting balances consistent with the PPUC's
findings in their Orders.
Effective September 1, 2002, Met-Ed and Penelec agreed to purchase a
portion of their PLR requirements from FES through a wholesale power sale
agreement. The PLR sale 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 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 a fixed price 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
16
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 current market prices.
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed,
Penelec and Penn are currently awaiting the PPUC to issue a final order in both
matters. The order will determine (1) the standards and benchmarks to be
utilized, and (2) the details required in the quarterly and annual reports.
On January 16, 2004, the PPUC initiated a formal investigation of
whether Met-Ed's, Penelec's and Penn's "service reliability performance
deteriorated to a point below the level of service reliability that existed
prior to restructuring" in Pennsylvania. Discovery has commenced in the
proceeding and Met-Ed's, Penelec's and Penn's testimony is due May 14, 2004.
Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ
has been directed to issue a Recommended Decision by September 30, 2004, in
order to allow the PPUC time to issue a Final Order by year end of 2004.
FirstEnergy is unable to predict the outcome of the investigation or the impact
of the PPUC order.
7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:
EITF Issue No. 03-6, "Participating Securities and the Two-Class Method
Under Financial Accounting Standards Board Statement No. 128, Earnings
per Share"
On March 31, 2004, the FASB ratified the consensus reached by the EITF
on Issue 03-6. The issue addresses a number of questions regarding the
computation of earnings per share by companies that have issued securities other
than common stock that contractually entitle the holder to participate in
dividends and earnings of a company when, and if, it declares dividends on its
common stock. The issue also provides further guidance in applying the two-class
method of computing earnings per share once it is determined that a security is
participating, including how to allocate undistributed earnings to such a
security. EITF 03-6 is effective for fiscal periods beginning after March 31,
2004. FirstEnergy is currently evaluating the effect of adopting EITF 03-6.
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly
referred to as special-purpose entities effective December 31, 2003 and for all
other types of entities effective March 31, 2004. Adoption of FIN 46R did not
have a material impact on FirstEnergy's financial statements for the quarter
ended March 31, 2004. See Note 2 for a discussion of variable interest entities.
For the quarter ended March 31, 2004, FirstEnergy evaluated, among
other entities, its power purchase agreements and determined that it is possible
that nine NUG entities might be considered variable interest entities.
FirstEnergy has requested but not received the information necessary to
determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is
the primary beneficiary. In most cases, the requested information was deemed to
be competitive and proprietary data. As such, FirstEnergy applied the scope
exception that exempts enterprises unable to obtain the necessary information to
evaluate entities under FIN 46R. The maximum exposure to loss from these
entities results from increases in the variable pricing component under the
contract terms and cannot be determined without the requested data. Purchased
power costs from these entities during the first quarters of 2004 and 2003 were
$51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million)
and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7
million), respectively. FirstEnergy is required to continue to make exhaustive
17
efforts to obtain the necessary information in future periods and is unable to
determine the possible impact of consolidating any such entity without this
information.
EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative
Instruments That Are Subject to SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, and Not "Held for Trading Purposes"
as Defined in EITF Issue 02-03, "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in
Energy Trading and Risk Management Activities."
In July 2003, the EITF reached a consensus that determining whether
realized gains and losses on physically settled derivative contracts not "held
for trading purposes" should be reported in the income statement on a gross or
net basis is a matter of judgment that depends on the relevant facts and
circumstances. The consideration of the facts and circumstances, including
economic substance, should be made in the context of the various activities of
the entity rather than based solely on the terms of the individual contracts.
The adoption of this consensus effective January 1, 2004, did not have a
material impact on the Companies' financial statements.
8 - SEGMENT INFORMATION:
FirstEnergy operates under two reportable segments: regulated services
and competitive services. The aggregate "Other" segments do not individually
meet the criteria to be considered a reportable segment. "Other" consists of
interest expense related to holding company debt; corporate support services and
the international businesses acquired in the 2001 merger. FirstEnergy's primary
segment is its regulated services segment, whose operations include the
regulated sale of electricity and distribution and transmission services by its
eight EUOC in Ohio, Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L,
Met-Ed, Penelec and ATSI). The competitive services business segment consists of
the subsidiaries (FES, FSG, MYR, MARBEL and FirstCom) that operate unregulated
energy and energy-related businesses, including the operation of generation
facilities of OE, CEI, TE and Penn resulting from the deregulation of the
Companies' electric generation business (see Note 6 - Regulatory Matters).
The regulated services segment designs, constructs, operates and
maintains FirstEnergy's regulated transmission and distribution systems. Its
revenues are primarily derived from electricity delivery and transition costs
recovery.
The competitive services segment has responsibility for FirstEnergy
generation operations as discussed under Note 6. As a result, its revenues
include all generation electric sales revenues (including the generation
services to regulated franchise customers who have not chosen an alternative
generation supplier) and all domestic unregulated energy and energy-related
services including commodity sales (both electricity and natural gas) in the
retail and wholesale markets, marketing, generation and sourcing of commodity
requirements, providing local and long-distance phone service, as well as other
competitive energy-application services.
Segment reporting in 2003 was reclassified to conform with the current
year business segment organizations and operations. Revenues from the
competitive services segment now include all generation revenues including
generation services to regulated franchise customers previously reported under
the regulated services segment and now exclude revenues from power supply
agreements with the regulated services segments previously reported as internal
revenues. The regulated services segment results now exclude generation sales
revenues and related generation commodity costs. Certain amounts (including
transmission and congestion charges) were reclassified among purchased power,
other operating costs and depreciation and amortization to conform with the
current year presentation of generation commodity costs. In addition, segment
results have been adjusted to reflect the reclassification of revenue, expense,
interest expense and tax amounts of divested businesses reflected as
discontinued operations (see Note 2).
18
Segment Financial Information
-----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
--------- ----------- ----- ------------ ------------
(In millions)
Three Months Ended:
March 31, 2004
--------------
External revenues..................... $ 1,295 $ 1,873 $ 7 $ 8(a) $ 3,183
Internal revenues..................... -- -- 120 (120)(b) --
Total revenues..................... 1,295 1,873 127 (112) 3,183
Depreciation and amortization......... 393 9 10 -- 412
Net interest charges.................. 106 12 69 (15)(b) 172
Income taxes.......................... 147 -- (31) -- 116
Net income (loss)..................... 216 -- (42) -- 174
Total assets.......................... 29,336 2,285 964 -- 32,585
Total goodwill........................ 5,981 136 -- -- 6,117
Property additions.................... 90 45 3 -- 138
March 31, 2003
--------------
External revenues..................... $ 1,309 $ 1,874 $ 34 $ 4 (a) $ 3,221
Internal revenues..................... -- -- 124 (124) (b) --
Total revenues..................... 1,309 1,874 158 (120) 3,221
Depreciation and amortization......... 355 12 9 -- 376
Net interest charges.................. 124 12 104 (34) (b) 206
Income taxes.......................... 189 (66) (29) -- 94
Income before discontinued operations and
cumulative effect of accounting change 257 (92) (51) -- 114
Net income (loss)..................... 358 (96) (44) -- 218
Total assets.......................... 30,417 2,449 1,421 -- 34,287
Total goodwill........................ 5,993 244 -- -- 6,237
Property additions.................... 118 79 27 -- 224
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.
19
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------------
2004 2003
---- ----
(In thousands, except per share amounts)
REVENUES:
Electric utilities........................................................ $ 2,177,033 $ 2,315,064
Unregulated businesses.................................................... 1,005,541 905,673
----------- -----------
Total revenues........................................................ 3,182,574 3,220,737
----------- -----------
EXPENSES:
Fuel and purchased power.................................................. 1,134,326 1,100,636
Purchased gas............................................................. 153,528 224,797
Other operating expenses.................................................. 841,615 926,585
Provision for depreciation and amortization............................... 412,232 376,363
General taxes............................................................. 179,085 178,067
----------- -----------
Total expenses........................................................ 2,720,786 2,806,448
----------- -----------
INCOME BEFORE INTEREST AND INCOME TAXES...................................... 461,788 414,289
----------- -----------
NET INTEREST CHARGES:
Interest expense.......................................................... 172,864 200,261
Capitalized interest...................................................... (6,470) (9,152)
Subsidiaries' preferred stock dividends................................... 5,281 14,542
------------ -----------
Net interest charges.................................................. 171,675 205,651
----------- -----------
INCOME TAXES................................................................. 116,114 94,258
----------- -----------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE............................................... 173,999 114,380
Discontinued operations (net of income taxes of $3,211,000) (Note 2)......... -- 1,975
Cumulative effect of accounting change (net of income taxes of
$72,516,000) (Note 2)..................................................... -- 102,147
----------- -----------
NET INCOME................................................................... $ 173,999 $ 218,502
=========== ===========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect
of accounting change.................................................... $0.53 $0.39
Discontinued operations (Note 2).......................................... -- --
Cumulative effect of accounting change (Note 2)........................... -- 0.35
----- -----
Net income................................................................ $0.53 $0.74
===== =====
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING.......................... 327,057 293,886
======= =======
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect
of accounting change.................................................... $0.53 $0.39
Discontinued operations (Note 2).......................................... -- --
Cumulative effect of accounting change (Note 2)........................... -- 0.35
----- -----
Net income................................................................ $0.53 $0.74
===== =====
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING........................ 329,034 294,877
======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK................................. $0.375 $0.375
====== ======
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.
20
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------------------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ 280,269 $ 113,975
Receivables-
Customers (less accumulated provisions of $51,127,000 and $50,247,000
respectively, for uncollectible accounts)...................................... 937,026 1,000,259
Other (less accumulated provisions of $30,257,000 and $18,283,000
respectively, for uncollectible accounts)...................................... 295,728 505,241
Letter of credit collateralization................................................. 277,763 --
Materials and supplies, at average cost-
Owned............................................................................ 337,473 325,303
Under consignment................................................................ 90,303 95,719
Prepayments and other.............................................................. 253,180 202,814
----------- -----------
2,471,742 2,243,311
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service......................................................................... 21,917,840 21,594,746
Less--Accumulated provision for depreciation....................................... 9,242,621 9,105,303
----------- -----------
12,675,219 12,489,443
Construction work in progress...................................................... 583,927 779,479
----------- -----------
13,259,146 13,268,922
----------- -----------
INVESTMENTS:
Nuclear plant decommissioning trusts............................................... 1,419,743 1,351,650
Investments in lease obligation bonds ............................................. 968,039 989,425
Letter of credit collateralization ................................................ -- 277,763
Other.............................................................................. 919,430 878,853
----------- -----------
3,307,212 3,497,691
----------- -----------
DEFERRED CHARGES:
Regulatory assets.................................................................. 6,722,641 7,076,923
Goodwill........................................................................... 6,117,000 6,127,883
Other.............................................................................. 706,795 695,218
----------- -----------
13,546,436 13,900,024
----------- -----------
$32,584,536 $32,909,948
=========== ===========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock............................... $ 1,736,737 $ 1,754,197
Short-term borrowings ............................................................. 133,999 521,540
Accounts payable................................................................... 548,221 725,239
Accrued taxes...................................................................... 701,458 669,529
Lease market valuation liability................................................... 84,800 84,800
Other.............................................................................. 760,656 716,862
----------- -----------
3,965,871 4,472,167
----------- -----------
CAPITALIZATION:
Common stockholders' equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
329,836,276 shares outstanding................................................. 32,984 32,984
Other paid-in capital............................................................ 7,054,006 7,062,825
Accumulated other comprehensive loss............................................. (343,826) (352,649)
Retained earnings................................................................ 1,655,919 1,604,385
Unallocated employee stock ownership plan common stock-
2,692,155 and 2,896,951 shares, respectively................................... (54,360) (58,204)
----------- -----------
Total common stockholders' equity............................................ 8,344,723 8,289,341
Preferred stock of consolidated subsidiaries not subject to mandatory redemption... 335,123 335,123
Long-term debt and other long-term obligations..................................... 10,150,067 9,789,066
----------- -----------
18,829,913 18,413,530
----------- -----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.................................................. 2,137,839 2,178,075
Asset retirement obligations....................................................... 1,198,132 1,179,493
Power purchase contract loss liability............................................. 2,597,820 2,727,892
Retirement benefits................................................................ 1,615,837 1,591,006
Lease market valuation liability................................................... 999,850 1,021,000
Other.............................................................................. 1,239,274 1,326,785
----------- -----------
9,788,752 10,024,251
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)....................................
----------- -----------
$32,584,536 $32,909,948
=========== ===========
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these balance sheets.
21
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
------------------------
2004 2003
---- ----
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 173,999 $ 218,502
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation and amortization................................ 412,232 376,363
Nuclear fuel and lease amortization........................................ 21,874 14,918
Other amortization, net.................................................... (4,723) (4,613)
Deferred costs recoverable as regulatory assets............................ (83,907) (94,311)
Deferred income taxes, net................................................. 12,397 28,141
Investment tax credits, net................................................ (6,474) (6,259)
Cumulative effect of accounting change (Note 2)............................ -- (174,663)
Income from discontinued operations (Note 2)............................... -- (1,975)
Receivables................................................................ 272,746 (1,898)
Materials and supplies..................................................... (6,754) 11,413
Accounts payable........................................................... (177,018) (7,115)
Accrued taxes.............................................................. 31,929 97,553
Accrued interest........................................................... 86,636 89,210
Deferred rents and sale/leaseback valuation liability...................... (16,297) (17,592)
Prepayments and other current assets....................................... (47,031) (69,673)
Other...................................................................... (19,986) 4,261
--------- ---------
Net cash provided from operating activities.............................. 649,623 462,262
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt............................................................. 581,558 297,696
Redemptions and Repayments-
Long-term debt............................................................. (268,920) (200,866)
Short-term borrowings, net................................................. (387,541) (237,490)
Net controlled disbursement activity......................................... (42,656) 14,444
Common stock dividend payments............................................... (122,465) (110,159)
--------- ---------
Net cash used for financing activities................................... (240,024) (236,375)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (138,406) (224,419)
Nonutility generation trust withdrawals (contributions)...................... (50,614) 106,327
Contributions to nuclear decommissioning trusts.............................. (25,370) (25,263)
Proceeds from asset sales.................................................... 11,439 60,572
Cash investments............................................................. 20,218 24,715
Other........................................................................ (60,572) (59,640)
--------- ---------
Net cash used for investing activities................................... (243,305) (117,708)
--------- ---------
Net increase in cash and cash equivalents....................................... 166,294 108,179
Cash and cash equivalents at beginning of period................................ 113,975 225,932
--------- ---------
Cash and cash equivalents at end of period...................................... $ 280,269 $ 334,111
========= =========
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.
22
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders 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, 2004, and the related consolidated
statements of income and cash flows for each of the three-month periods ended
March 31, 2004 and 2003. 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, 2003, 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 asset retirement obligations as of January 1,
2003 as discussed in Note 2(F) to those consolidated financial statements and
the Company's change in its method of accounting for the consolidation of
variable interest entities as of December 31, 2003 as discussed in Note 9 to
those consolidated financial statements) dated February 25, 2004, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2003, 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 7, 2004
23
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
FirstEnergy's Business
FirstEnergy Corp. is a registered public utility holding company
headquartered in Akron, Ohio that provides regulated and competitive energy
services (see Results of Operations - Business Segments). FirstEnergy continues
to pursue its goal of being the leading supplier of energy and related services
in portions of the midwest and mid-Atlantic regions of the United States, where
it sees the best opportunities for growth. FirstEnergy's 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
continue providing 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 the 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 eight
electric utility operating companies provide transmission and distribution
services and comprise the nation's fifth largest investor-owned electric system,
serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania
and New Jersey.
Competitive services are principally provided by FES, FSG, MARBEL, MYR
and FirstEnergy's majority owned FirstCom. Through its 50% interest in GLEP,
MARBEL is involved in the exploration and production of oil and natural gas, and
transmission and marketing of natural gas. Other subsidiaries provide a wide
range of services, including heating, ventilation, air-conditioning,
refrigeration, process piping, plumbing, electrical and facility control systems
and high-efficiency electrotechnologies. Telecommunication services are also
provided - local and long-distance phone service is provided to more than 65,000
customers. While competitive revenues have increased since 2001, regulated
energy services continue to provide, in aggregate, the majority of FirstEnergy's
revenues and earnings.
Beginning in 2001, Ohio utilities that offered both competitive and
regulated retail electric services were required to implement a corporate
separation plan approved by the PUCO - one which provided a clear separation
between regulated and competitive operations. FES provides competitive retail
energy services while the EUOC provide regulated transmission and distribution
services. FGCO, a wholly owned subsidiary of FES, leases fossil and
hydroelectric plants from the EUOC and operates those plants. Under the terms of
the current corporate separation plan, the transfer of ownership of EUOC
non-nuclear generating assets to FGCO would be substantially completed by the
end of the Ohio market development period. All of the EUOC power supply
requirements for the Ohio Companies (OE, CEI, and TE) and Penn are provided by
FES to satisfy their PLR obligations, as well as their grandfathered wholesale
contracts.
FirstEnergy acquired international assets through the merger with GPU
in November 2001. GPU Capital and its subsidiaries provided electric
distribution services in foreign countries (see Results of Operations -
Discontinued Operations). GPU Power and its subsidiaries owned and operated
generation facilities in foreign countries. As of January 30, 2004,
substantially all of the international operations were divested (see Note 5) -
supporting FirstEnergy's commitment to focus on its core electric business.
FirstEnergy's current focus includes: (1) enhancing customer service;
(2) optimizing its generation portfolio; (3) minimizing unplanned extended
generation outages; (4) effectively managing commodity supplies and risks; (5)
reducing its cost structure; (6) enhancing its credit profile and financial
flexibility; (7) managing the skills and diversity of its workforce; (8)
continuing safe operations; and (9) satisfactory resolution of the pending Ohio
rate plan.
Reclassifications
As further discussed in Note 8 to the Consolidated Financial
Statements, amounts for purchased power, other operating costs and provisions
for depreciation and amortization in FirstEnergy's 2003 Consolidated Statements
of Income were reclassified to conform with the current year presentation of
generation commodity costs. These reclassifications did not change previously
reported 2003 results. In addition, as discussed in Note 2 to the Consolidated
Financial Statements, reporting of discontinued operations also resulted in the
reclassification of revenues, expenses and taxes.
24
Results of Operations
Net Income and Earnings Per Share
Net income in the first quarter of 2004 was $174 million or $0.53 per
share of common stock (basic and diluted), compared to $218 million or $0.74 per
share of common stock (basic and diluted) in the first quarter of 2003. Net
income in the first quarter of 2003 included after-tax earnings from
discontinued operations of $2 million and an after-tax credit of $102 million
from the cumulative effect of an accounting change (basic and diluted earnings
per share of $0.35) due to the adoption of SFAS 143. Excluding the cumulative
effect of the accounting change in the first quarter of 2003, earnings increased
to $0.53 per share of common stock (basic and diluted) from $0.39 per share of
common stock (basic and diluted). Two major factors contributed to this improved
performance -- reduced maintenance costs incurred as part of the extended outage
at Davis-Besse (as the plant prepared for restart in 2004) and the absence of
any nuclear refueling outage in the first three months of 2004 versus one
refueling outage in the same period last year.
In the third quarter of 2003, FirstEnergy completed the issuance and
sale of 32.2 million shares of common stock (see Cash Flows from Financing
Activities below) which were included in the calculation of earnings per share
on a weighted average basis in the first quarter of 2004. The additional shares
reduced earnings per share of common stock by $0.06 (basic and diluted).
Three Months Ended
March 31,
-----------------------
FirstEnergy 2004 2003
-----------------------------------------------------------------------
(In millions)
Total revenues............................. $3,183 $3,221
Income before interest and income taxes.... 462 414
Income before discontinued operations
and cumulative effect of accounting change 174 114
Discontinued operations.................... -- 2
Cumulative effect of accounting change..... -- 102
-----------------------------------------------------------------------
Net Income................................. $ 174 $ 218
-----------------------------------------------------------------------
Basic Earnings Per Share:
Income before discontinued operations and
cumulative effect of accounting change $0.53 $0.39
Discontinued operations................. -- --
Cumulative effect of accounting change.. -- 0.35
------------------------------------------------------------------------
Net Income................................. $0.53 $0.74
========================================================================
Diluted Earnings Per Share:
Income before discontinued operations and
cumulative effect of accounting change $0.53 $0.39
Discontinued operations................. -- --
Cumulative effect of accounting change.. -- 0.35
------------------------------------------------------------------------
Net Income................................. $0.53 $0.74
========================================================================
Results of Operations - First Quarter of 2004 Compared With the First
Quarter of 2003
Total revenues decreased $38 million in the first quarter of 2004,
compared to the same period last year. The sources of changes in total revenues
are summarized in the following table:
25
Three Months Ended
March 31,
------------------ Increase
Sources of Revenue Changes 2004 2003 (Decrease)
---------------------------------------------------------------------
(In millions)
Retail Electric Sales:
EUOC - Wires and shopping deferrals $ 1,159 $ 1,213 $ (54)
- Generation 758 785 (27)
FES.............................. 171 121 50
Wholesale Electric Sales:
EUOC............................. 124 221 (97)
FES.............................. 444 284 160
------------------------------------------------------------------
Electric Sales..................... 2,656 2,624 32
------------------------------------------------------------------
Transmission Revenues.............. 76 9 67
Gas Sales.......................... 165 245 (80)
Other Revenues:
Regulated services................ 60 86 (26)
Competitive services.............. 220 222 (2)
International...................... -- 8 (8)
Other.............................. 6 27 (21)
-------------------------------------------------------------------
Total Revenues..................... $3,183 $3,221 $ (38)
===================================================================
Changes in electric generation sales and distribution deliveries in
the first quarter of 2004 from the same quarter of 2003 are summarized in the
following table:
Increase
Changes in KWH Sales (Decrease)
-----------------------------------------------------
Electric Generation Sales:
Retail -
EUOC.................................. (6.2)%
FES................................... 24.4 %
Wholesale............................... 19.5 %
-----------------------------------------------------
Total Electric Generation Sales.......... 4.1 %
=====================================================
EUOC Distribution Deliveries:
Residential............................. (0.2)%
Commercial.............................. -- %
Industrial.............................. 0.8 %
-----------------------------------------------------
Total Distribution Deliveries............ 0.2 %
=====================================================
Retail sales by FirstEnergy's EUOC remain the largest source of
revenues, contributing over 70% of electric revenues and over 60% of total
revenues. The following major factors contributed to the $81 million reduction
in retail electric revenues from FirstEnergy's regulated services segment in the
first quarter of 2004 compared to the same period in 2003.
Sources of the Changes in EUOC Retail Electric Revenue
------------------------------------------------------
Increase (Decrease) (In millions)
------------------------------------------------------
Changes in Demand:
Alternative suppliers.................. $(56)
Economic and other ................... 3
------------------------------------------------------
(53)
------------------------------------------------------
Changes in Price:
Rate changes........................... (32)
Shopping credit........................ (7)
Rate mix and other..................... 11
------------------------------------------------------
(28)
------------------------------------------------------
Net Decrease............................. $ (81)
======================================================
Reductions in both demand and prices contributed to lower EUOC retail
electric revenues. Customers shopping in FirstEnergy's franchise areas for
alternative energy suppliers remained the largest single factor for the reduced
demand. Alternative suppliers provided 24.1% of the total energy delivered to
retail customers in the first quarter of 2004, compared to 18.9% in the same
period of 2003. Distribution throughput increased slightly. Milder weather in
the first quarter of 2004 compared to the unusually cold temperatures in the
first quarter of 2003 contributed to reduced residential deliveries. However,
economic and other factors contributed to increased industrial deliveries in the
first quarter of 2004 compared to the same period last year. On July 25, 2003,
the NJBPU announced its JCP&L base electric rate proceeding decision (see
Regulatory Matters - New Jersey), which reduced JCP&L's distribution rates
effective August 1, 2003. The lower rates reduced revenues by $32 million in the
first quarter of 2004. EUOC sales to wholesale customers decreased by $97
26
million on a 44.1% reduction in kilowatt-hour sales - JCP&L's sales represented
substantially all of the decrease.
Electric sales by FES increased by $210 million primarily from
additional spot sales to the wholesale market ($160 million). Higher electric
sales to the wholesale market resulted from an 11% increase in internal
generation available from FirstEnergy's nuclear (15%) and fossil (9%) generating
plants. Retail sales increased by $50 million, primarily from customers within
FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity
choice program.
FirstEnergy's regulated and unregulated subsidiaries record purchase
and sales transactions with PJM on a gross basis in accordance with EITF 99-19.
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, 2004 and 2003 are summarized
as follows:
Three Months Ended
March 31,
----------------------
2004 2003
-------------------------------------------------------
(In millions)
Sales......................... $366 $336
Purchases..................... 330 361
--------------------------------------------------------
FirstEnergy's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from PJM 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 (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.
Natural gas sales were $80 million lower primarily due to the
expiration of FES customer choice program contracts and reduced sales to large
industrial and commercial customers. Sales to large commercial and industrial
customers declined in the first quarter of 2004 from the same period in 2003
reflecting fewer customers and more moderate temperatures.
The generation margin in the first quarter of 2004 improved by $53
million compared to the same period in 2003 as electric generation revenues
increased faster than the related costs for fuel and purchased power. Higher
electric generation sales resulted from additional sales to the wholesale market
which benefited from increased internal generation. The improved generation
margin occurred despite higher replacement power costs associated with the
extended Davis-Besse outage (see Davis-Besse Restoration below). The gas margin
decreased $9 million on falling sales.
Three Months Ended
March 31,
---------------------- Increase
Energy Revenue Net of Fuel and Purchased Power 2004 2003 (Decrease)
----------------------------------------------------------------------------------------------------
(In millions)
Electric generation revenue........................... $1,497 $1,411 $86
Fuel and purchased power.............................. 1,134 1,101 33
--------------------------------------------------------------------------------------------------
Net................................................... 363 310 53
--------------------------------------------------------------------------------------------------
Gas revenue(1)........................................ 158 238 (80)
Purchased gas......................................... 154 225 (71)
--------------------------------------------------------------------------------------------------
Net................................................... 4 13 (9)
--------------------------------------------------------------------------------------------------
Total Net............................................. $ 367 $ 323 $44
==================================================================================================
(1) Excludes 50% share of GLEP earnings.
Other factors contributing to the $48 million increase in income
before interest and taxes include:
o Lower nuclear production costs of $72 million primarily as a
result of no nuclear refueling outages in the first quarter
of 2004 compared to one refueling outage at Beaver Valley
Unit 1 in last year's first quarter ($32 million) and
reduced incremental maintenance costs at the Davis-Besse
Plant ($35 million) related to its restart;
o A net decrease of $19 million in other operating expenses as
a result of reduced postretirement benefit plan expenses
(see Postretirement Plans below) offset in part by
additional severance costs and increased benefit costs for
active employees; and
27
o Lower non-nuclear operating expenses primarily reflecting
deferred planned outage work at FirstEnergy's fossil
generating units ($10 million).
Partially offsetting these lower costs were three factors:
o Reduced revenues from distribution deliveries ($54 million);
o Charges for depreciation and amortization that increased by
$36 million primarily due to: higher charges resulting from
increased amortization of the Ohio transition plan
regulatory assets ($23 million), reduced shopping incentive
deferrals under the Ohio transition plan ($4 million) and
additional stranded cost amortization for Met-Ed and Penelec
($22 million). Partially offsetting these increases were
reduced depreciation rates resulting from the JCP&L rate
case ($11 million); and
o Higher energy delivery costs of $10 million principally due
to increased tree trimming activities and to a lesser extent
JCP&L's accelerated reliability program.
Income before discontinued operations and the cumulative effect of
accounting changes increased $60 million from the comparable period last year.
The change reflects reduced net interest charges of $34 million and increased
income taxes of $22 million in addition to the changes discussed above. The
decrease in interest expense is the result of debt and preferred stock
redemptions and other financing activities. Proceeds from the issuance of 32.2
million shares of common stock in September 2003 accelerated the repayment of
debt. Redemption and refinancing activities for debt and preferred stock
aggregated approximately $653 million during the first quarter of 2004. The
redemption and refinancing activities and pollution control note repricings are
expected to result in annualized savings of $5 million. FirstEnergy also
exchanged existing fixed-rate payments on outstanding debt (notional amount of
$1.35 billion at March 31, 2004) 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 $11 million in the
first quarter of 2004 as a result of these swaps.
Discontinued Operations
Net income in the first quarter of 2003 included after-tax earnings
from discontinued operations of $2 million reflecting the reclassification of
revenues and expenses associated with divestitures of its Argentina and Bolivia
international businesses and the FSG subsidiaries, Colonial Mechanical, Webb
Technologies and Ancoma, Inc., as well as NEO.
Cumulative Effect of Accounting Change
Results in the first quarter of 2003 included an after-tax credit to
net income of $102 million recorded upon the adoption of SFAS 143 in January
2003. 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 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
$1.11 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 $1.24 billion.
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 and the reversal of accumulated estimated removal costs for
non-regulated generation assets, was a $175 million increase to income, or $102
million net of income taxes.
Postretirement Plans
Resurgent equity markets in 2003, amendments to FirstEnergy's health
care benefits plan in the first quarter of 2004 and the new Medicare Act signed
by President Bush in December 2003 combined to reduce pensions and other
postretirement costs -- despite continued increases in health care costs and
projected trend rates. Combined, these employee benefit expenses decreased by
$26 million in the first quarter of 2004 compared to the same period in 2003.
The following table summarizes the net pension and OPEB expense (excluding
amounts capitalized) for the three months ended March 31, 2004 and 2003.
28
Three Months Ended
Postretirement Benefits Expense(1) March 31,
-----------------------------------------------------
2004 2003
---- ----
(In millions)
Pension...................... $20 $31
OPEB......................... 26 41
-----------------------------------------------------
Total...................... $46 $72
=====================================================
(1).Excludes the capitalized portion of postretirement benefits
costs (see Note 4 for total costs).
The decrease in pension and OPEB expenses are included in various cost
categories and have contributed to other cost reductions discussed above. See
"Critical 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. In the first quarter of
2004, management made certain changes in presenting results for these two
segments (see Note 8). The regulated services segment no longer includes a
portion of generation services. The regulated services segment designs,
constructs, operates and maintains FirstEnergy's regulated transmission and
distribution systems. Its revenues are primarily derived from electricity
delivery and transition cost recovery. All generation services are now reported
in the competitive services segment. As a result, its revenues include all
generation electric sales revenues (including the generation services to
regulated franchise customers who have not chosen an alternative generation
supplier) and all domestic unregulated energy and energy-related services
including commodity sales (both electricity and natural gas) in the retail and
wholesale markets, marketing, generation, commodity sourcing and other
competitive energy-application services such as heating, ventilating and
air-conditioning. "Other" consists of interest expense related to holding
company debt; corporate support services and the international businesses that
were substantially divested by the first quarter of 2004. FirstEnergy's two
major business segments include all or a portion of the following business
entities:
o The regulated services segment includes the regulated sale
of electricity and distribution and transmission services by
its eight electric utility operating companies in Ohio,
Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L,
Met-Ed, Penelec and ATSI)
o The competitive services business segment consists of the
subsidiaries (FES, FSG, MYR, MARBEL and FirstCom) that
operate unregulated energy and energy-related businesses,
including the operation of generation facilities of OE, CEI,
TE and Penn resulting from the deregulation of the
Companies' electric generation business (see Note 6 -
Regulatory Matters).
Financial results discussed below include revenues and expenses from
transactions among FirstEnergy's business segments. A reconciliation of segment
financial results to consolidated financial results is provided in Note 8 to the
consolidated financial statements. Net income (loss) by business segment was as
follows:
Three Months Ended
March 31,
Net Income (Loss) ---------------------
By Business Segment 2004 2003
----------------------------------------------------
(In millions)
Regulated services......... $ 216 $ 358
Competitive services....... -- (96)
Other...................... (42) (44)
----------------------------------------------------
Total...................... $ 174 $ 218
====================================================
Regulated Services - First Quarter 2004 versus First Quarter 2003
Financial results for the regulated services segment were as follows:
Three Months Ended
March 31,
------------------- Increase
Regulated Services 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Total revenues............................... $1,295 $1,309 $ (14)
Income before interest and income taxes....... 468 570 (102)
Income before cumulative effect of accounting
changes.................................... 216 257 (41)
Net Income.................................... 216 358 (142)
- --------------------------------------------------------------------------------
29
The change in operating revenues resulted from the following sources:
Three Months Ended
March 31,
--------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
----------------------------------------------------------------------
(In millions)
Electric sales............. $1,159 $1,213 $(54)
Other sales................ 136 96 40
----------------------------------------------------------------------
Total Sales................ $1,295 $1,309 $(14)
======================================================================
The decrease in electric revenues resulted from:
o A net decrease of $54 million in retail sales -- a $58
million decrease in revenues from distribution deliveries
partially offset by a $4 million decrease in shopping
incentives to customers.
o A net $40 million increase in other sales primarily due to
higher transmission revenues.
Lower revenues combined with increased expenses resulted in an $102
million decrease in income before interest and income taxes. Higher expenses
included a $53 million increase in operating expenses from additional
transmission expenses and energy delivery costs, as well as increased
depreciation and amortization charges of $38 million.
Competitive Services - First Quarter 2004 versus First Quarter 2003
Financial results for the competitive services segment were as
follows:
Three Months Ended
March 31,
------------------ Increase
Competitive Services 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Total revenues................................... $1,873 $1,874 $ (1)
Income (Loss) before interest and income tax benefit 13 (146) 159
Income (Loss) before discontinued operations and
cumulative effect of accounting changes....... -- (92) 92
Net income (loss)................................ -- (96) 96
- --------------------------------------------------------------------------------
The change in total revenues resulted from the following sources:
Three Months Ended
March 31,
------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
----------------------------------------------------------------------
(In millions)
Electric....................... $1,497 $1,411 $86
Natural Gas sales.............. 165 245 (80)
Energy-related sales........... 178 187 (9)
Other.......................... 33 31 2
----------------------------------------------------------------------
Total Revenues................. $1,873 $1,874 $(1)
======================================================================
The increase in electric revenues resulted from:
o Higher retail generation sales from sales through customer
choice programs ($50 million) partially offset by lower
generation sales from the EUOC ($27 million); and
o Increased wholesale revenues of $160 million from FES
(primarily into the spot market) offset in part by a $97
million decrease in EUOC sales to wholesale customers.
Natural gas sales were $80 million lower primarily due to the
expiration of customer choice programs in which FES participated and reduced
sales to large industrial and commercial customers. Sales to large commercial
and industrial customers declined reflecting fewer customers and more moderate
temperatures than last year.
The generation margin increased $53 million as electric generation
revenues increased faster than the related costs for fuel and purchased power.
Higher electric generation revenues resulted from additional sales to the
wholesale market which benefited from increased internal generation. The
improved generation margin occurred despite higher replacement power costs
associated with the extended Davis-Besse outage (see Davis-Besse Restoration
below). The margin on gas sales decreased $9 million on falling sales. Together
with a higher net energy margin, reduced expenses contributed to a net $159
30
million increase in income before interest and income taxes. Major expense
factors included the following:
o Lower nuclear production costs of $72 million primarily as a
result of no nuclear refueling outages in the first quarter
of 2004 compared to one refueling outage at Beaver Valley
Unit 1 in the first quarter last year ($32 million) and
reduced incremental maintenance costs at the Davis-Besse
Plant ($35 million) related to its restart.
o A $10 million decrease in non-nuclear operating expenses
primarily from deferred planned outage work at fossil
generating units.
o Reduced postretirement benefit plan expenses (see
Postretirement Plans above) offset in part by increased
benefit costs for active employees.
Capital Resources and Liquidity
FirstEnergy's cash requirements in 2004 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 two 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 $1.25 billion of revolving credit facilities. In the first quarter of
2004, FirstEnergy received $124 million of cash dividends from its subsidiaries
and paid $122 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, 2004, FirstEnergy had $280 million of cash and cash
equivalents, compared with $114 million as of December 31, 2003. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
FirstEnergy's consolidated net cash from operating activities is
provided by its regulated and competitive energy services businesses (see
Results of Operations - Business Segments above). Net cash provided from
operating activities was $650 million in the first quarter of 2004 and $462
million in the first quarter of 2003, summarized as follows:
Three Months Ended
March 31,
--------------------
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 508 $ 363
Working capital and other............ 142 99
-------------------------------------------------------------
Total................................ $ 650 $ 462
=============================================================
(1)Includes net income, depreciation and
amortization, deferred income taxes, investment
tax credits and major noncash charges.
Net cash provided from operating activities increased $188 million due
to a $145 million increase in cash earnings and a $43 million increase from
changes in working capital. The working capital change resulted primarily from
the net proceeds from the settlement of FirstEnergy's claim against NRG, Inc.
for the terminated sale of four power plants.
Cash Flows From Financing Activities
The following table provides details regarding security issuances and
redemptions during the first quarter of 2004 and 2003:
31
Three Months Ended
March 31,
--------------------
Securities Issued or Redeemed 2004 2003
----------------------------------------------------------------------
(In millions)
New Issues
Pollution control notes................... $112 $ --
Senior notes.............................. 317 250
Unsecured notes........................... 153 --
Long-term revolver........................ -- 50
Other, primarily debt discount............ -- (2)
-----------------------------------------------------------------------
$582 $298
Redemptions
First mortgage bonds...................... $92 $40
Pollution control notes................... -- 50
Secured notes............................. 42 108
Long-term revolving credit................ 135 --
Other, primarily redemption premiums...... -- 3
-----------------------------------------------------------------------
$269 $201
Short-term Borrowings, Net .................... $(388) $(237)
------------------------------------------------------------------------
Net cash used for the above financing activities declined by $65
million in the first quarter of 2004 from the first quarter of 2003. The
decrease in funds used for financing activities resulted from increased
financing of $284 million that exceeded $219 million of additional redemptions
and repayments during the first quarter of 2004 compared to the same period of
2003.
FirstEnergy had approximately $134 million of short-term indebtedness
as of March 31, 2004 compared to approximately $522 million as of December 31,
2003. Available borrowing capability as of March 31, 2004 included the
following:
FirstEnergy
Borrowing Capability Holding Company OE Total
- ----------------------------------------------------------------------------
(In millions)
Long-Term Revolver................ $ 875 $375 $1,250
Utilized.......................... (175) -- (175)
Letters of Credit................. (183) -- (183)
- ----------------------------------------------------------------------------
Net............................... 517 375 892
- ----------------------------------------------------------------------------
Short-Term Facilities:
Revolver.......................... 375 125 500
Bank ............................. -- 34 34
- ----------------------------------------------------------------------------
................................... 375 159 534
- ----------------------------------------------------------------------------
Utilized:
Revolver.......................... -- -- --
Bank.............................. -- -- --
- ----------------------------------------------------------------------------
Net............................... 375 159 534
- ----------------------------------------------------------------------------
Amount Available.................. $ 892 $534 $1,426
============================================================================
As of March 31, 2004, the Ohio companies and Penn had the aggregate
capability to issue approximately $3.2 billion of additional first mortgage
bonds (FMB) on the basis of property additions and retired bonds, although
unsecured senior note indentures entered into by OE and CEI in 2004 limit each
company's ability to issue secured debt, including FMBs, subject to certain
exceptions. JCP&L, Met-Ed and Penelec no longer issue FMB other than (in the
case of JCP&L and Penelec) 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, 2004, JCP&L and
Penelec had the aggregate capability to issue $545 million of additional senior
notes using FMB collateral. Because Met-Ed satisfied the provisions of its
senior note indenture for the release of all FMBs held as collateral for senior
notes in March 2004, it is no longer required to issue FMBs as collateral for
future issuances of senior notes and therefore not limited as to the amount of
senior notes it may issue. Based upon applicable earnings coverage tests in
their respective charters, OE, Penn, TE and JCP&L could issue a total of $3.4
billion of preferred stock (assuming no additional debt was issued) as of March
31, 2004. CEI, Met-Ed and Penelec have no restrictions on the issuance of
preferred stock.
In October 2003, FirstEnergy restructured its $1 billion 364-day
revolving credit facility through a syndicated bank offering that was completed
on October 23, 2003. The new syndicated FirstEnergy facilities consist of a $375
million 364-day revolving credit facility and a $375 million three-year
revolving credit facility. Also on October 23, 2003, OE entered into a
syndicated $125 million 364-day revolving credit facility and a syndicated $125
million three-year revolving credit facility. Combined with an existing
syndicated $500 million three-year facility for FirstEnergy, maturing in
November 2004, and an existing syndicated $250 million two-year facility for OE,
32
maturing in May 2005, FirstEnergy's primary syndicated credit facilities total
$1.75 billion. These facilities are intended to provide liquidity to meet the
short-term working capital requirements of FE and its subsidiaries. Available
borrowing capacity under existing facilities totaled $1.426 billion as of March
31, 2004.
Borrowings under these facilities are conditioned on FirstEnergy
and/or OE maintaining compliance with certain financial covenants in the
agreements. FirstEnergy, under its $375 million 364-day and $375 million
three-year facilities, and OE, under its $125 million 364-day and $250 million
two-year facilities, are each required to maintain a debt to total
capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed
charge coverage ratio of no less than 2 to 1. Under its $500 million three-year
facility, FirstEnergy is required to maintain a debt to total capitalization
ratio of no more than 0.69 to 1 and a contractually-defined fixed charge
coverage ratio for the most recent fiscal quarter of no less than 1.5 to 1.
FirstEnergy and OE are in compliance with all of these financial covenants. The
ability to draw on each of these facilities is also conditioned upon FirstEnergy
or OE making certain representations and warranties to the lending banks prior
to drawing on their respective facilities, including a representation that there
has been no material adverse change in its business, its condition (financial or
otherwise), its results of operations, or its prospects.
None of FirstEnergy's or OE's primary credit facilities contain
provisions, whereby their ability to borrow would be restricted or denied, or
repayment of outstanding loans under the facilities accelerated, as a result of
any change in the credit ratings of FirstEnergy or OE by any of the
nationally-recognized rating agencies. Borrowings under each of the primary
facilities do contain "pricing grids", whereby the cost of funds borrowed under
the facilities is related to the credit ratings of the company borrowing the
funds.
FirstEnergy's regulated companies have the ability to borrow from each
other and the holding company to meet their short-term working capital
requirements. A similar but separate arrangement exists among its competitive
companies. FirstEnergy Service Company administers these two money pools and
tracks surplus funds of FirstEnergy and the respective regulated and competitive
subsidiaries, as well as proceeds available from bank borrowings. For the
regulated companies, available bank borrowings include $1.75 billion from
FirstEnergy's and OE's revolving credit facilities. For the competitive
companies, available bank borrowings include only the $1.25 billion of
FirstEnergy's revolving credit facility. Companies receiving a loan under the
money pool agreements must repay the principal amount of such a loan, together
with accrued interest, within 364 days of borrowing the funds. For the regulated
and competitive money pools, the rate of interest is the same for each company
receiving a loan from their respective pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in
the first quarter of 2004 was 1.30% for the regulated companies' pool and 1.57%
for the competitive companies' pool.
In January and March of 2004, FirstEnergy executed four
fixed-to-floating interest rate swap agreements with notional amounts of $50
million each on underlying EUOC senior notes and subordinated debentures with an
average fixed rate of 5.73%.
In March 2004, Met-Ed, Penelec and Penn completed on-balance sheet,
receivable financing transactions which allow each company to borrow up to $80
million, $75 million and $25 million, respectively. The borrowing rates are
based on bank commercial paper rates. Met-Ed and Penelec are required to pay
annual facility fees of 0.30% on the entire finance limit. Penn Power is
required to pay an annual facility fee of 0.40% on the entire finance limit. The
facilities were undrawn at the end of March 2004. These facilities mature on
March 29, 2005.
On March 25, 2004, Met-Ed issued $250 million principal amount of
4.875% Senior Notes due 2014. A portion of the proceeds were used to redeem $50
million aggregate principal amount of outstanding Met-Ed Medium Term Notes
(MTNs) having a weighted average interest cost of 6.39%, and to pay down
short-term debt. Met-Ed also intends to use a portion of the proceeds to redeem
$100 million principal amount of Met-Ed Capital Trust's 7.35% Trust Preferred
Securities in the second quarter of 2004 and to pay at maturity $40 million
principal amount of Met-Ed's 6.34% MTNs maturing August 27, 2004.
On March 31, 2004, Penelec issued $150 million principal amount of
5.125% Senior Notes due 2014. The proceeds of this transaction were used to
redeem $125 million principal amount of 5.75% Senior Notes that matured on April
1, 2004 and to repay short-term debt.
On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes
due 2016. The proceeds of this transaction will be used to redeem $40 million of
7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs
due 2005. The remaining proceeds will be used to fund the mandatory redemption
of JCPL's $160 million of 7.125% FMB due October 1, 2004 and to reduce
short-term debt.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
33
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net cash flows used for investing activities totaled $243 million in
the first quarter of 2004, compared to net cash flows of $118 million used for
investing activities for the same period of 2003. The $125 million change
primarily resulted from a refunding payment of $51 million to a NUG trust fund
in the first quarter 2004 compared to $106 million of withdrawals in the first
quarter of 2003.
The following table summarizes first quarter 2004 investments by
FirstEnergy's regulated services and competitive services segments:
Summary of First Quarter 2004 Property
Cash Used for Investing Activities Additions Investments Other Total
- --------------------------------------------------------------------------------
Sources (Uses) (In millions)
Regulated Services.................... $ (90) $(79)(1) $ (2) $(171)
Competitive Services.................. (45) 20 2 (23)
Other................................. (3) (26) (20) (49)
- --------------------------------------------------------------------------------
Total............................ $(138) $(85) $(20) $(243)
================================================================================
(1) Includes a $51 million refunding payment to a NUG trust fund.
During the remaining three quarters of 2004, capital requirements for
property additions and capital leases are expected to be approximately $666
million, including $86 million for nuclear fuel. FirstEnergy has additional
requirements of approximately $902 million to meet sinking fund requirements for
preferred stock and maturing long-term debt during the remainder of 2004. These
cash requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
FirstEnergy's current forecast reflects expenditures of approximately
$2.3 billion for property additions and improvements from 2004-2006, of which
approximately $720 million is applicable to 2004. Investments for additional
nuclear fuel during the 2004-2006 period are estimated to be approximately $315
million, of which approximately $86 million applies to 2004. During the same
periods, the Companies' nuclear fuel investments are expected to be reduced by
approximately $281 million and $91 million, respectively, as the nuclear fuel is
consumed.
As of March 31, 2004, FirstEnergy had $278 million in deposits pledged
as collateral to secure reimbursement obligations related to certain letters of
credit supporting OE's obligations to lessors under the Beaver Valley Unit 2
sale and leaseback arrangements. The deposits had previously been classified as
a noncurrent investment. OE expects to replace the cash collateralized LOC with
a structure that would not require cash collateral. OE anticipates using the
cash from the deposit to repay short term debt in the third quarter of 2004 and
for other general corporate purposes.
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 letters of credit.
As of March 31, 2004, the maximum potential future payments under
outstanding guarantees and other assurances totaled $1.9 billion as summarized
below:
34
Maximum
Guarantees and Other Assurances Exposure
------------------------------------------------------------
(In millions)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts(1)...... $ 862
Other (2)................................... 149
--------------------------------------------------------
1,011
Surety Bonds.................................. 240
Letters of Credit (3)(4)...................... 677
--------------------------------------------------------
Total Guarantees and Other Assurances....... $ 1,928
==========================================================
(1) Issued for a one-year term, with a 10-day
termination right by
FirstEnergy.
(2) Issued for various terms.
(3) Includes letters of credit of $183 million issued
for various terms under letter of credit capacity
available in FirstEnergy's revolving credit
agreement.
(4) Includes unsecured letters of credit of approximately
$216 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by CEI and TE, as
well as collateralized letters of credit of $278
million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by OE.
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 financings where the law might otherwise limit
the counterparties' claims. If demands of a counterparty were to exceed the
ability of a subsidiary to satisfy existing obligations, 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 ongoing energy-related activities is remote.
While these types of guarantees are normally parental commitments for
the future payment of subsidiary obligations, subsequent to the occurrence of a
credit rating downgrade or "material adverse event" the immediate payment of
cash collateral or provision of an LOC may be required. The following table
summarizes collateral provisions as of March 31, 2004:
Collateral Paid
Total ----------------------- Remaining
Collateral Provisions Exposure Cash Letters of Credit Exposure (1)
- --------------------------------------------------------------------------------
(In millions)
Rating downgrade............ $228 $133 $18 $ 77
Adverse event............... 232 -- 69 163
- --------------------------------------------------------------------------------
Total....................... $460 $133 $87 $240
================================================================================
(1) As of April 12, 2004, FirstEnergy's remaining exposure was $237
million, with $141 million of cash and $72 million of
letters of credit provided as collateral.
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.
FirstEnergy has also guaranteed the obligations of the operators of
the TEBSA project in Colombia, up to a maximum of $6 million (subject to
escalation) under the project's operations and maintenance agreement. In
connection with the sale of TEBSA in January 2004, the purchaser indemnified
FirstEnergy against any loss under this guarantee. FirstEnergy has provided the
TEBSA project lenders a $60 million LOC, which is renewable and declines yearly
based upon the senior outstanding debt of TEBSA. This LOC granted FirstEnergy
the ability to sell its remaining 20.1% interest in Avon.
35
OFF-BALANCE SHEET ARRANGEMENTS
FirstEnergy has obligations that are not included on its Consolidated
Balance Sheets related to the sale and leaseback arrangements involving Perry
Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected
as part of the operating lease payments. The present value of these sale and
leaseback operating lease commitments, net of trust investments, total $1.4
billion as of March 31, 2004.
CEI and TE sell substantially all of their retail customer receivables
to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the
receivables to a trust (a "qualified special purpose entity" under SFAS 140)
under an asset-backed securitization agreement. This arrangement provided $200
million of off-balance sheet financing as of March 31, 2004.
As of March 31, 2004, off-balance sheet arrangements include certain
statutory business trusts created by CEI, Met-Ed and Penelec to issue trust
preferred securities aggregating $285 million. These trusts were included in the
consolidated financial statements of FirstEnergy prior to the adoption of FIN
46R, but have subsequently been deconsolidated under FIN 46R (see Note 7 - New
Accounting Standards and Interpretations). This deconsolidation has not resulted
in any change in outstanding debt.
FirstEnergy has equity ownership interests in certain various
businesses that are accounted for using the equity method. There are no
undisclosed material contingencies related to these investments. Certain
guarantees that FirstEnergy does not expect to have a material current or future
effect on its financial condition, liquidity or results of operations are
disclosed under contractual obligations above.
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 fluctuating
electricity, natural gas, coal, nuclear fuel and emission allowance 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 2004 is summarized in the
following table:
36
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, 2004................... $67 $ 12 $ 79
New contract value when entered............................... -- -- --
Additions/change in value of existing contracts............... (4) 6 2
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. 1 (6) (5)
- -------------------------------------------------------------------------------------------------
Outstanding net asset as of March 31, 2004 (1)................ 64 12 76
- -------------------------------------------------------------------------------------------------
Non-commodity Net Assets as of March 31, 2004:
Interest Rate Swaps (2)....................................... -- 38 38
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (3)... $64 $ 50 $114
=================================================================================================
Impact of Changes in Commodity Derivative Contracts: (4)
Income Statement Effects (Pre-Tax)............................ $(1) $ -- $ (1)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $-- $ -- $ --
Regulatory Liability.......................................... $(2) $ -- $ (2)
(1) Includes $59 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 $24 million of derivative contract fair value decrease, as of
March 31, 2004, 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.
Derivatives are included on the Consolidated Balance Sheet as of March
31, 2004 as follows:
Balance Sheet Classification Non-Hedge Hedge Total
-----------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $ 10 $11 $ 21
Other Liabilities................. (6) -- (6)
Non-current-
Other Deferred Charges............ 60 44 104
Other Noncurrent Liabilities...... -- (5) (5)
----------------------------------------------------------------------
Net assets........................ $ 64 $50 $ 114
======================================================================
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 2004(1) 2005 2006 2007 Thereafter Total
- -----------------------------------------------------------------------------------------------------
(In millions)
Prices actively quoted(2)............. $ 9 $ 2 $-- $-- $-- $11
Other external sources(3)............. 12 10 -- -- -- 22
Prices based on models................ -- -- 10 10 23 43
- -----------------------------------------------------------------------------------------------------
Total(4)........................... $21 $12 $10 $10 $23 $76
=====================================================================================================
(1) For the last three quarters of 2004.
(2) Exchange traded.
(3) Broker quote sheets.
(4) Includes $59 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.
37
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, 2004.
Based on derivative contracts held as of March 31, 2004, an adverse 10% change
in commodity prices would decrease net income by approximately $1 million for
the next twelve months.
Interest Rate Swap Agreements
During the first quarter of 2004, FirstEnergy entered into
fixed-to-floating interest rate swap agreements, as part of its ongoing effort
to manage the interest rate risk of its debt portfolio. These derivatives are
treated as fair value hedges of a 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, fixed interest rates and
interest payment dates match those of the underlying obligations. As a result of
the differences between fixed and variable debt rates, interest expense was $11
million lower in the first quarter of 2004. As of March 31, 2004, the debt
underlying the interest rate swaps had a weighted average fixed interest rate of
5.44%, which the swaps have effectively converted to a current weighted average
variable interest rate of 2.11%.
Interest Rate Swaps
March 31, 2004 December 31, 2003
---------------------------- -----------------------------
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 $ 5 $200 2006 $ 1
100 2008 2 50 2008 --
100 2010 1 100 2010 1
100 2011 6 100 2011 1
450 2013 14 350 2013 (1)
150 2015 (3) 150 2015 (10)
150 2018 9 150 2018 1
50 2019 4 50 2019 1
50 2031 __--
- -------------------------------------------------------------------------------------------
$1,350 $38 $1,150 $ (6)
- --------------------------------------------------------------------------------------------
Floating to Fixed Rate (1)
(Cash flow hedges) $ 7 2005 $ --
- -------------------------------------------------------------------------------------------
(1) FirstEnergy no longer had the cash flow hedges as of January 30, 2004
as a result of the divestiture of Los Amigos Leasing Company, Ltd.. -
a subsidiary of GPU Power.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $821 million and $779
million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in an $82 million
reduction in fair value as of March 31, 2004.
CREDIT RISK
Credit risk is the risk of an obligor's failure to meet the terms of
any investment contract, loan agreement or otherwise perform as agreed. Credit
risk arises from all activities in which success depends on issuer, borrower or
counterparty performance, whether reflected on or off the balance sheet.
FirstEnergy engages in transactions for the purchase and sale of commodities
including gas, electricity, coal and emission allowances. These transactions are
often with major energy companies within the industry.
FirstEnergy maintains stringent credit policies with respect to its
counterparties to manage overall credit risk. This includes performing
independent risk evaluations, actively monitoring portfolio trends and using
collateral and contract provisions to mitigate exposure. As part of its credit
program, FirstEnergy aggressively manages the quality of its portfolio of energy
contracts evidenced by a current weighted average risk S&P rating for energy
contract counterparties of "BBB." As of March 31, 2004 the largest credit
concentration to any counterparty was 8% - which is a currently rated investment
grade counterparty.
Outlook
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. 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 nonnuclear generating assets to FGCO
38
will be substantially completed by the end of the Ohio market development
period. 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.
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 customers in the EUOC's
service areas;
o allowing recovery of transition costs (sometimes referred to
as stranded investment) not otherwise recoverable in a
competitive generation market;
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and transition costs recovery charges;
o deregulating the electric generation businesses;
o continuing regulation of the EUOC's transmission and
distribution systems; and
o requiring corporate separation of regulated and unregulated
business activities.
Regulatory assets are costs which the respective regulatory agencies
have authorized for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. All of the
regulatory assets are expected to continue to be recovered under the provisions
of the respective transition and regulatory plans as discussed below. The
regulatory assets of the individual companies are as follows:
March 31, December 31,
Regulatory Assets 2004 2003 (Decrease)
----------------------------------------------------------------------------
(In millions)
OE............................ $1,348 $1,451 $ (103)
CEI........................... 1,022 1,056 (34)
TE............................ 432 459 (27)
Penn.......................... 15 28 (13)
JCP&L......................... 2,457 2,558 (101)
Met-Ed........................ 990 1,028 (38)
Penelec....................... 459 497 (38)
---------------------------------------------------------------------------
Total......................... $6,723 $7,077 $(354)
===========================================================================
Regulatory assets by source are as follows:
March 31, December 31, Increase
Regulatory Assets By Source 2004 2003 (Decrease)
-----------------------------------------------------------------------------
(In millions)
Regulatory transition charge............. $6,088 $6,427 $(339)
Customer shopping incentives............. 413 371 42
Customer receivables for future income taxes 315 340 (25)
Societal benefits charge................. 81 81 --
Loss on reacquired debt.................. 74 75 (1)
Postretirement benefits.................. 74 77 (3)
Nuclear decommissioning, decontamination
and spent fuel disposal costs.......... (106) (96) (10)
Component removal costs.................. (327) (321) (6)
Property losses and unrecovered plant costs 65 70 (5)
Other.................................... 46 53 (7)
---------------------------------------------------------------------------
Total.................................... $6,723 $7,077 $(354)
===========================================================================
39
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
Ohio
FirstEnergy's transition plan for the Ohio EUOC included approval for
recovery of transition costs, including regulatory assets, 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; granting 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 EUOC's retail customers; and freezing customer prices 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 EUOC 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.
The Ohio EUOC 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. Subject to approval by the PUCO, recovery will be
accomplished by extending the respective transition cost recovery period.
On October 21, 2003, the Ohio EUOC filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
40
o A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing the Ohio EUOC's
support of energy efficiency and economic development
efforts.
Under the first option, an auction would be conducted to secure
generation service for the Ohio EUOC's customers. Beginning in 2006, customers
would pay market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of the Ohio EUOC's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity if shopping drops below 20%. Under the proposed
plan, the Ohio EUOC are requesting:
o Extension of the transition cost amortization period for OE
from 2006 to 2007; for CEI from 2008 to mid-2009 and for TE
from mid-2007 to mid-2008;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
o Ability to initiate a request to increase generation rates
under certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. Oral arguments were held before
the PUCO on April 21 and a decision is expected from the PUCO in the Spring of
2004.
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's two August 2002 rate
filings requested increases in base electric rates of approximately $98 million
annually and requested the recovery of deferred energy 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. In
July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision
which reduced JCP&L's annual revenues by approximately $62 million effective
August 1, 2003. The NJBPU decision also provided for an interim return on equity
of 9.5% on JCP&L's rate base for the next six to twelve months. During that
period, JCP&L will initiate another proceeding to request recovery of additional
costs incurred to enhance system reliability. In that proceeding, the NJBPU
could increase the return on equity to 9.75% or decrease it to 9.25%, depending
on its assessment of the reliability of JCP&L's service. Any reduction would be
retroactive to August 1, 2003. The revenue decrease in the decision consists of
a $223 million decrease in the electricity delivery charge, a $111 million
increase due to the August 1, 2003 expiration of annual customer credits
previously mandated by the New Jersey transition legislation, a $49 million
increase in the MTC tariff component, and a net $1 million increase in the SBC
charge. The MTC allowed for the recovery of $465 million in deferred energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary settlement agreement between
certain parties. As a result, JCP&L recorded charges to net income for the year
ended December 31, 2003, aggregating $185 million ($109 million net of tax)
consisting of the $153 million deferred energy costs and other regulatory
assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on
August 15, 2003 with respect to the following issues: (1) the disallowance of
the $153 million deferred energy costs; (2) the reduced rate of return on
equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On
October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU
decision and order is issued. This is expected to occur in the second quarter of
2004.
On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
JCP&L implement a series of actions to improve reliability in the area affected
by the outages. The NJBPU adopted the findings and recommendations of the
Interim Report on December 17, 2003, and ordered JCP&L to implement the
recommended actions on a staggered basis, with initial actions to be completed
by March 31, 2004. JCP&L expects to spend $12.5 million implementing these
actions during 2004. In late 2003, in accordance with a Settlement Stipulation
concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to
conduct an audit of the planning, operations and maintenance practices, policies
41
and procedures of JCP&L. The audit was expanded to include the July 2003 outage
and was completed in January 2004. JCP&L is awaiting the issuance of the final
audit report and is unable to predict the outcome of the audit; no liability has
been accrued as of March 31, 2004.
On April 28, 2004, the NJBPU directed JCP&L to file testimony by the
end of May 2004, either supporting a continuation of the current level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers,
or, alternatively, proposing a reduction, termination or capping of the funding.
JCP&L cannot predict the outcome of this matter.
Pennsylvania
In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate proceedings which approved the
FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy
costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs
in excess of amounts reflected in their capped generation rates retroactive to
January 1, 2001. This PLR deferral accounting procedure was later reversed in a
February 2002 Commonwealth Court of Pennsylvania decision. The court decision
affirmed the PPUC decision regarding approval of the merger, remanding the
decision to the PPUC only with respect to the issue of merger savings.
FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred
energy costs which aggregated $287.1 million, reflecting the potential adverse
impact of the then pending Pennsylvania Supreme Court decision whether to review
the Commonwealth Court decision. FirstEnergy recorded in 2002 an aggregate
non-cash charge of $55.8 million ($32.6 million net of tax) to income for the
deferred costs incurred subsequent to the merger. The reserve for the remaining
$231.3 million of deferred costs increased goodwill by an aggregate net of tax
amount of $135.3 million.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the ALJ for hearings, directed Met-Ed and Penelec to file a position
paper on the effect of the Commonwealth Court order on the Settlement
Stipulation and allowed other parties to file responses to the position paper.
Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the
Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring
settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the CTC rates and shopping credits that were in effect prior to the
June 21, 2001 order to be effective upon one day's notice. In response to that
order, Met-Ed and Penelec filed these supplements to their tariffs to become
effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered accounting treatment regarding the CTC rate/shopping credit swap
should follow the ratemaking, and that the PPUC's findings would not impair
their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA
(an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and
Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund and, denying
Met-Ed's and Penelec's other clarification requests and granting ARIPPA's
petition with respect to the retroactive accounting treatment of the changes to
the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed
an Objection with the Commonwealth Court asking that the Court reverse the
PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC
rates that were in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying Met-Ed's and Penelec's objection without explanation. Due to the
vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an
Application for Clarification with the judge. Concurrent with this filing,
Met-Ed and Penelec, in order to preserve their rights, also filed with the
Commonwealth Court both a Petition for Review of the PPUC's October 16 and
October 22 Orders, and an application for reargument, if the judge, in his
clarification order, indicates that Met-Ed's and Penelec's objection was
intended to be denied on the merits. In addition to these findings, Met-Ed and
Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly
reports for the twelve months ended December 31, 2001 and 2002, and for the
first two quarters of 2003, reflecting balances consistent with the PPUC's
findings in their Orders.
Effective September 1, 2002, Met-Ed and Penelec agreed to purchase a
portion of their PLR requirements from FES through a wholesale power sale
agreement. The PLR sale 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 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 a fixed price 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 current market prices.
42
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. FirstEnergy is
currently awaiting the PPUC to issue a final order in both matters. The order
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports.
On January 16, 2004, the PPUC initiated a formal investigation of
whether Met-Ed's, Penelec's and Penn's "service reliability performance
deteriorated to a point below the level of service reliability that existed
prior to restructuring" in Pennsylvania. Discovery has commenced in the
proceeding and Met-Ed's, Penelec's and Penn's testimony is due May 14, 2004.
Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ
has been directed to issue a Recommended Decision by September 30, 2004, in
order to allow the PPUC time to issue a Final Order by year end of 2004.
FirstEnergy is unable to predict the outcome of the investigation or the impact
of the PPUC order.
Davis-Besse Restoration
On April 30, 2002, the 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 was 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. This process led to the
NRC's March 8, 2004 approval of Davis-Besse's restart.
Restart activities included both hardware and management issues. In
addition to refurbishment and installation work at the plant, FENOC made
significant management and human performance changes with the intent of
enhancing the proper safety culture throughout the workforce. The focus of
activities in the first quarter of 2004 involved management and human
performance issues. As a result, incremental maintenance costs declined in the
first quarter of 2004 compared to the same period in 2003 as emphasis shifted to
performance issues; however, replacement power costs were higher in the first
quarter of 2004. The plant's generating equipment was tested in March in
preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed
generating electricity at 100% power.
Incremental costs associated with the extended Davis-Besse outage for
the first quarter of 2004 and 2003 were as follows:
Three Months Ended
March 31,
------------------- Increase
Costs of Davis-Besse Extended Outage 2004 2003 (Decrease)
- -----------------------------------------------------------------------------
(In millions)
Incremental Expense
Replacement power................. $64 $52 $ 12
Maintenance....................... 1 36 (35)
- --------------------------------------------------------------------------
Total......................... $65 $88 $(23)
==========================================================================
Incremental Net of Tax Expense...... $38 $52 $(14)
==========================================================================
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. 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 that 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.
Overall, FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict future change in regulatory policies and
what, if any, the effects of such change would be.
The EPA has proposed the Interstate Air Quality Rule to
"cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase
II in 2015). According to the EPA, SO2 emissions would be reduced by
approximately 3.6 million tons in 2010, across states covered by the rule, with
reductions ultimately reaching more than 5.5 million tons annually. NOx emission
reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015. The future cost of compliance with these proposed regulations may be
substantial and will depend on whether and how they are ultimately implemented
by the states in which the Companies operate affected facilities.
43
On December 15, 2003, the EPA proposed two different approaches to
reduce mercury emissions from coal-fired power plants. The first approach would
require plants to install controls known as "maximum achievable control
technologies" (MACT) based on the type of coal burned. According to the EPA, if
implemented, the MACT proposal would reduce nationwide mercury emissions from
coal-fired power plants by 14 tons to approximately 34 tons per year. The second
approach proposes a cap-and-trade program that would reduce mercury emissions in
two distinct phases. Initially, mercury emissions would be reduced by 2010 as a
"co-benefit" from implementation of SO2 and NOx emission caps under the EPA's
proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade
program would be implemented in 2018 to cap nationwide mercury emissions from
coal-fired power plants at 15 tons per year. The EPA has agreed to choose
between these two options and issue a final rule by March 15, 2005. The future
cost of compliance with these regulations may be substantial.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on
FirstEnergy's financial condition and results of operations. Management is
unable to predict the ultimate outcome of this matter and no liability has been
accrued as of March 31, 2004.
In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but it failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012. The Companies cannot currently estimate the financial
impact of climate change policies although the potential restrictions on CO2
emissions could require significant capital and other expenditures. However, the
CO2 emissions per kilowatt-hour of electricity generated by the Companies is
lower than many regional competitors due to the Companies' diversified
generation sources which includes low or non-CO2 emitting gas-fired and nuclear
generators.
Power Outages
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L's territory. In an investigation into the
causes of the outages and the reliability of the transmission and distribution
systems of all four New Jersey electric utilities, the NJBPU concluded that
there was not a prima facie case demonstrating that, overall, JCP&L provided
unsafe, inadequate or improper service to its customers. Two class action
lawsuits (subsequently consolidated into a single proceeding) were filed in New
Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies,
seeking compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
Since July 1999, this litigation has involved a substantial amount of
legal discovery including interrogatories, request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L employees. In addition, there have been many motions filed and
argued by the parties involving issues such as the primary jurisdiction and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate Division determined that the trial court has proper jurisdiction
over this litigation. In August 2002, the trial court granted partial summary
judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, and strict products liability. In
November 2003, the trial court granted JCP&L's motion to decertify the class and
denied plaintiffs' motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings have been appealed to the Appellation Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of March 31, 2004.
44
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Regulatory Matters above). As many of these initiatives already
were in process and budgeted in 2004, FirstEnergy does not believe that any
incremental expenses associated with additional initiatives undertaken during
2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Davis-Besse
FENOC received a subpoena in late 2003 from a grand jury sitting in
the United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis-Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks, among other things, suspension of the Davis-Besse operating
license. If it were ultimately determined that FirstEnergy has legal liability
or is otherwise made subject to enforcement action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on FirstEnergy's financial condition and results of operations.
Other Legal Matters
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant not otherwise discussed above are described below.
Legal proceedings have been filed against FirstEnergy in connection
with, among other things, the restatements in August 2003, by FirstEnergy and
its Ohio utility subsidiaries of previously reported results, the August 14th
power outage described above, and the extended outage at the Davis-Besse Nuclear
Power Station. Depending upon the particular proceeding, the issues raised
include alleged violations of federal securities laws, breaches of fiduciary
duties under state law by FirstEnergy directors and officers, and damages as a
result of one or more of the noted events. The securities cases have been
consolidated into one action pending in federal court in Akron. The derivative
actions filed in federal court likewise have been consolidated as a separate
matter, also in federal court in Akron. There also are pending derivative
actions in state court.
FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two regulatory proceedings initiated at the PUCO in response to complaints
alleging failure to provide reasonable and adequate service stemming primarily
from the August 14th power outage. FirstEnergy is vigorously defending these
actions, but cannot predict the outcome of any of these proceedings or whether
any further regulatory proceedings or legal actions may be instituted against
them. In particular, if FirstEnergy were ultimately determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on its financial condition and results of operations.
Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outage. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed.
45
CRITICAL ACCOUNTING POLICIES
FirstEnergy prepares its consolidated financial statements in
accordance with GAAP. 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.
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 - $6.7 billion as of March 31, 2004. 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
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 a
significant number of commodity contracts, as well as interest rate swaps, which
increase the impact of derivative accounting judgments.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues,
recognizing revenue for electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
electricity sales to individual customers is based on meter readings, which
occur on a systematic basis throughout the month. At the end of each month,
electricity delivered to customers since the last meter reading is estimated and
a corresponding accrual for unbilled revenues is recognized. The determination
of unbilled revenues requires management to make estimates regarding electricity
available for retail load, transmission and distribution line losses, demand by
customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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.
46
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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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.
Ohio Transition Cost Amortization
In connection with FirstEnergy's transition plan, the PUCO determined
allowable transition costs based on amounts recorded on the regulatory books of
the Ohio electric utilities. These costs exceeded those deferred or capitalized
on FirstEnergy's balance sheet prepared under GAAP since they included certain
costs which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments). FirstEnergy
uses an effective interest method for amortizing its transition costs, often
referred to as a "mortgage-style" amortization. The interest rate under this
method is equal to the rate of return authorized by the PUCO in the transition
plan for each respective company. In computing the transition cost amortization,
FirstEnergy includes only the portion of the transition revenues associated with
transition costs included on the balance sheet prepared under GAAP. Revenues
collected for the off balance sheet costs and the return associated with these
costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS 144, FirstEnergy periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset might 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 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, FirstEnergy recognizes an ARO for the
future decommissioning of its nuclear power plants. The ARO liability represents
an estimate of the fair value of FirstEnergy's current obligation related to
nuclear decommissioning and the retirement of other assets. A fair value
measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. FirstEnergy used an expected cash flow approach (as
discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and
Present Value in Accounting Measurements") to measure the fair value of the
nuclear decommissioning ARO. This approach applies probability weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.
The scenarios consider settlement of the ARO at the expiration of the nuclear
power plants' current license and settlement based on an extended license term.
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 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), the goodwill is tested for
impairment. If an impairment is indicated FirstEnergy recognizes a loss -
calculated as the difference between the implied fair value of a reporting
47
unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual
review was completed in the third quarter of 2003. As a result of that review, a
non-cash goodwill impairment charge of $122 million was recognized in the third
quarter of 2003, reducing the carrying value of FSG. 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, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates
to its regulated services segment.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
EITF Issue No. 03-6, "Participating Securities and the Two-Class Method
Under Financial Accounting Standards Board Statement No. 128, Earnings
per Share"
On March 31, 2004, the FASB ratified the consensus reached by the EITF
on Issue 03-6. The issue addresses a number of questions regarding the
computation of earnings per share by companies that have issued securities other
than common stock that contractually entitle the holder to participate in
dividends and earnings of a company when, and if, it declares dividends on its
common stock. The issue also provides further guidance in applying the two-class
method of computing earnings per share once it is determined that a security is
participating, including how to allocate undistributed earnings to such a
security. EITF 03-06 is effective for fiscal periods beginning after March 31,
2004. FirstEnergy is currently evaluating the effect of adopting EITF 03-6.
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly
referred to as special-purpose entities effective December 31, 2003 and for all
other types of entities effective March 31, 2004. Adoption of FIN 46R did not
have a material impact on FirstEnergy's financial statements for the quarter
ended March 31, 2004.
For the quarter ended March 31, 2004, FirstEnergy evaluated, among
other entities, its power purchase agreements and determined that it is possible
that nine NUG entities might be considered variable interest entities.
FirstEnergy has requested but not received the information necessary to
determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is
the primary beneficiary. In most cases, the requested information was deemed to
be competitive and proprietary data. As such, FirstEnergy applied the scope
exception that exempts enterprises unable to obtain the necessary information to
evaluate entities under FIN 46R. The maximum exposure to loss from these
entities results from increases in the variable pricing component under the
contract terms and cannot be determined without the requested data. Purchased
power costs from these entities during the first quarters of 2004 and 2003 were
$51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million)
and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7
million), respectively. FirstEnergy is required to continue to make exhaustive
efforts to obtain the necessary information in future periods and is unable to
determine the possible impact of consolidating any such entity without this
information.
EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative
Instruments That Are Subject to SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, and Not "Held for Trading Purposes"
as Defined in EITF Issue 02-03, "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in
Energy Trading and Risk Management Activities."
In July 2003, the EITF reached a consensus that determining whether
realized gains and losses on physically settled derivative contracts not "held
for trading purposes" should be reported in the income statement on a gross or
net basis is a matter of judgment that depends on the relevant facts and
circumstances. The consideration of the facts and circumstances, including
economic substance, should be made in the context of the various activities of
the entity rather than based solely on the terms of the individual contracts.
The adoption of this consensus effective January 1, 2004, did not have a
material impact on the Companies' financial statements.
48
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2004 2003
-------- --------
(In thousands)
OPERATING REVENUES.............................................................. $743,295 $742,743
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 15,070 12,850
Purchased power.............................................................. 249,881 243,828
Nuclear operating costs...................................................... 79,641 125,368
Other operating costs........................................................ 81,474 90,273
-------- --------
Total operation and maintenance expenses................................... 426,066 472,319
Provision for depreciation and amortization.................................. 124,729 108,385
General taxes................................................................ 48,566 48,256
Income taxes................................................................. 61,574 43,701
-------- --------
Total operating expenses and taxes......................................... 660,935 672,661
-------- --------
OPERATING INCOME................................................................ 82,360 70,082
OTHER INCOME.................................................................... 12,471 13,501
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 94,831 83,583
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 16,589 24,488
Allowance for borrowed funds used during construction and capitalized interest (1,381) (1,380)
Other interest expense....................................................... 2,890 2,478
Subsidiaries' preferred stock dividend requirements.......................... 640 912
-------- --------
Net interest charges....................................................... 18,738 26,498
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 76,093 57,085
Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 2) -- 31,720
------- --------
NET INCOME...................................................................... 76,093 88,805
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 561 659
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 75,532 $ 88,146
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.
49
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------- -----------
(In thousands)
ASSETS
UTILITY PLANT:
In service...................................................................... $5,304,122 $5,269,042
Less-Accumulated provision for depreciation..................................... 2,611,122 2,578,899
---------- ----------
2,693,000 2,690,143
---------- ----------
Construction work in progress-
Electric plant................................................................ 143,478 145,380
Nuclear Fuel.................................................................. 554 554
---------- ----------
144,032 145,934
---------- ----------
2,837,032 2,836,077
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds............................................ 383,088 383,510
Letter of credit collateralization.............................................. -- 277,763
Nuclear plant decommissioning trusts............................................ 394,705 376,367
Long-term notes receivable from associated companies ........................... 209,271 508,594
Other........................................................................... 56,131 59,102
---------- ----------
1,043,195 1,605,336
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents....................................................... 1,323 1,883
Receivables-
Customers (less accumulated provisions of $8,714,000 and $8,747,000,
respectively, for uncollectible accounts)................................... 267,315 280,538
Associated companies.......................................................... 500,570 436,991
Other (less accumulated provisions of $1,724,000 and $2,282,000
for uncollectible accounts)................................................. 29,887 28,308
Letter of credit collateralization.............................................. 277,763 --
Notes receivable from associated companies...................................... 616,912 366,501
Materials and supplies, at average cost......................................... 82,575 79,813
Prepayments and other........................................................... 26,219 14,390
---------- ----------
1,802,564 1,208,424
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................... 1,363,242 1,477,969
Property taxes.................................................................. 59,279 59,279
Unamortized sale and leaseback costs............................................ 64,284 65,631
Other........................................................................... 64,353 64,214
---------- ----------
1,551,158 1,667,093
---------- ----------
$7,233,949 $7,316,930
========== ==========
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.......................................... (35,657) (38,693)
Retained earnings............................................................. 544,466 522,934
---------- ----------
Total common stockholder's equity........................................... 2,607,538 2,582,970
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
Long-term debt and other long-term obligations.................................. 1,160,452 1,179,789
---------- ----------
3,868,060 3,862,829
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock............................ 428,438 466,589
Short-term borrowings-
Associated companies.......................................................... 67,849 11,334
Other......................................................................... 131,367 171,540
Accounts payable-
Associated companies.......................................................... 512,386 271,262
Other......................................................................... 7,834 7,979
Accrued taxes................................................................... 248,768 560,345
Accrued interest................................................................ 24,157 18,714
Other........................................................................... 99,116 58,680
---------- ----------
1,519,915 1,566,443
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes............................................... 824,832 867,691
Accumulated deferred investment tax credits..................................... 72,664 75,820
Asset retirement obligation..................................................... 322,929 317,702
Retirement benefits............................................................. 342,952 331,829
Other........................................................................... 282,597 294,616
---------- ----------
1,845,974 1,887,658
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3).................................
---------- ----------
$7,233,949 $7,316,930
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these balance sheets.
50
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
----------------------------
2004 2003
--------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 76,093 $ 88,805
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation and amortization................................ 124,729 108,385
Nuclear fuel and lease amortization........................................ 11,261 7,106
Deferred income taxes, net................................................. (26,387) 7,683
Investment tax credits, net................................................ (3,658) (3,704)
Cumulative effect of accounting change (Note 2)............................ -- (54,109)
Receivables................................................................ (51,935) (29,909)
Materials and supplies..................................................... (2,762) (1,298)
Accounts payable........................................................... 240,979 14,470
Accrued taxes.............................................................. (311,577) 6,051
Accrued interest........................................................... 5,443 2,437
Deferred lease costs....................................................... 33,030 31,683
Prepayments and other current assets ...................................... (11,829) (14,893)
Accrued retirement benefit obligations..................................... 11,123 2,679
Accrued compensation, net.................................................. 4,404 (5,802)
Other...................................................................... 16,562 (6,067)
--------- ---------
Net cash provided from operating activities.............................. 115,476 153,517
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt............................................................. 30,000 --
Short-term borrowings, net................................................. 16,341 --
Redemptions and Repayments-
Long-term debt............................................................. (97,001) (19,493)
Short-term borrowings, net................................................. -- (232,278)
Dividend Payments-
Common stock............................................................... (54,000) (13,000)
Preferred stock............................................................ (561) (659)
--------- ---------
Net cash used for financing activities................................... (105,221) (265,430)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (37,661) (68,367)
Contributions to nuclear decommissioning trusts.............................. (7,885) (7,885)
Nuclear decommissioning trust investments.................................... (10,453) 4,777
Associated company loan activities, net...................................... 48,912 173,250
Other........................................................................ (3,728) 3,946
--------- ---------
Net cash provided from (used for) investing activities................... (10,815) 105,721
--------- ---------
Net decrease in cash and cash equivalents....................................... (560) (6,192)
Cash and cash equivalents at beginning of period................................ 1,883 20,512
--------- ---------
Cash and cash equivalents at end of period...................................... $ 1,323 $ 14,320
========= =========
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.
51
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, 2004, and the related consolidated
statements of income and cash flows for each of the three-month periods ended
March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change
in its method of accounting for asset retirement obligations as of January 1,
2003 as discussed in Note 1(F) to those consolidated financial statements and
the Company's change in its method of accounting for the consolidation of
variable interest entities as of December 31, 2003 as discussed in Note 6 to
those consolidated financial statements) dated February 25, 2004, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2003, 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 7, 2004
52
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE
and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and
Pennsylvania, providing regulated electric distribution services. OE and Penn
(OE Companies) also provide generation services to those customers electing to
retain them as their power supplier. The OE Companies provide power directly to
wholesale customers under previously negotiated contracts, as well as to
alternative energy suppliers under OE's transition plan. The OE Companies have
unbundled the price of electricity into its component elements -- including
generation, transmission, distribution and transition charges. Power supply
requirements of the OE Companies are provided by FES -- an affiliated company.
Results of Operations
- ---------------------
Earnings on common stock in the first quarter of 2004 decreased to $76
million from $88 million in the first quarter of 2003. Earnings on common stock
in the first quarter of 2003 included an after-tax credit of $32 million from
the cumulative effect of an accounting change due to the adoption of SFAS 143.
Income before the cumulative effect was $76 million in the first three months of
2004, compared to $57 million for the same period of 2003. Improved results in
the first quarter of 2004 reflect lower operating expenses - primarily nuclear
operating costs, and reduced financing costs compared with the first quarter of
2003. Partially offsetting these improvements were higher nuclear fuel and
purchased power costs and increased amortization of regulatory assets.
Operating revenues increased by $0.6 million or 0.1% in the first
quarter of 2004 compared with the same period in 2003. The higher revenues
primarily resulted from additional sales to FES which were substantially offset
by lower generation retail sales to residential and commercial customers and
reduced revenue from distribution throughput. Total retail electric revenues
decreased by $7 million in the first quarter of 2004 compared to the first
quarter of 2003 reflecting reduced consumption due principally to milder weather
and a continued sluggish economy in our service area ($13 million) partially
offset by higher composite prices from a change in customer sales by class ($6
million).
Kilowatt-hour sales to retail customers declined by 3.3% in the first
quarter of 2004 compared to the same quarter of 2003, which reduced generation
sales revenue by $2 million. The decline reflected the increase of 2.3
percentage points in electric generation services provided by alternative
suppliers as a percent of total sales delivered in OE's franchise area in 2004
from the first quarter of 2003. In addition, distribution deliveries decreased
by 1.6% in the first quarter of 2004 compared with the first quarter of 2003,
with declines in all customer sectors (residential, commercial and industrial).
Sales revenues from wholesale customers increased by $10 million in
the first quarter of 2004 compared to the same period of 2003, due to a 23%
increase in nuclear generation available for sale to FES partially offset by
lower composite prices. The increased generation was due to the absence in 2004
of the Beaver Valley Unit 1 refueling outage in 2003.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2004 from the same quarter of 2003 are summarized in the
following table:
Changes in Kilowatt-Hour Sale
---------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. (3.3)%
Wholesale............................... 9.1%
---------------------------------------------------
Total Electric Generation Sales........... 2.2%
===================================================
Distribution Deliveries:
Residential............................. (2.1)%
Commercial.............................. (0.6)%
Industrial.............................. (1.8)%
----------------------------------------------------
Total Distribution Deliveries............. (1.6)%
====================================================
53
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $12 million in the
first quarter of 2004 from the first quarter of 2003. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
-----------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ 2
Purchased power ................................. 6
Nuclear operating costs.......................... (45)
Other operating costs............................ (9)
-------------------------------------------------------------
Total operation and maintenance expenses....... (46)
Provision for depreciation and amortization...... 16
General taxes.................................... --
Income taxes..................................... 18
------------------------------------------------------------
Total operating expenses and taxes............. $(12)
=============================================================
Higher fuel costs in the first quarter of 2004, compared with the same
quarter of 2003, resulted from increased nuclear generation - 23%. Purchased
power costs increased by $6 million reflecting higher unit costs which were
partially offset by lower kilowatt-hour purchases due to the decreased
requirements for retail generation sales. Lower nuclear operating costs occurred
in large part due to the absence of the Beaver Valley Unit 1 (100% ownership)
outage that occurred in the first quarter of 2003. The decrease in other
operating costs reflects in part lower employee benefit costs.
Charges for depreciation and amortization increased by $16 million in
the first quarter of 2004 compared to the first quarter of 2003 primarily from
two factors - increased amortization of the Ohio transition regulatory assets
($14 million) and lower shopping incentive deferrals ($1 million), partially
offset by increased regulatory asset deferrals of $2 million.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $8
million in the first quarter of 2004 from the same period last year, reflecting
redemptions and refinancings since the first quarter of 2003. OE Companies' net
debt redemptions totaled $55 million during the first quarter of 2004 and are
expected to result in annualized savings of $4 million (excluding change in
revolver facilities).
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 $32 million. The cumulative 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
million increase to income, or $32 million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
OE's cash requirements in 2004 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, 2004, OE had $1 million of cash and cash equivalents,
compared with $2 million as of December 31, 2003. The major sources for changes
in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided by operating activities during the first quarter of
2004, compared with the corresponding period in 2003 were as follows:
54
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $230 $183
Working capital and other............ (115) (29)
-------------------------------------------------------------
Total................................ $115 $154
=============================================================
(1) Includes net income, depreciation and amortization, deferred
income taxes, investment tax credits and major noncash
charges.
Net cash from operating activities decreased $39 million due to an $86
million increase in funds used for working capital -- that decrease was offset
in part by a $47 million increase in cash earnings. The decrease from working
capital and other changes primarily reflects the change in cash requirements for
accounts payable to associated companies of $227 million and accrued taxes of
$318 million for the first quarter of 2004 as compared to 2003. Both variances
reflect offsetting changes of $249 million for the reallocation of tax
liabilities between associated companies related to the tax sharing agreement.
Cash Flows From Financing Activities
In the first quarter of 2004, net cash used for financing activities
decreased to $105 million from $265 million in the same period last year. The
decrease resulted from increased short-term borrowings partially offset by an
increase in common stock dividend payments to FirstEnergy.
OE had approximately $618 million of cash and temporary investments
(which include short-term notes receivable from associated companies) and
approximately $199 million of short-term indebtedness as of March 31, 2004.
Available borrowing capability under bilateral bank facilities totaled $159
million as of March 31, 2004. The OE Companies had the capability to issue $2.1
billion of additional first mortgage bonds (FMB) on the basis of property
additions and retired bonds, although unsecured senior note indentures entered
into by OE in 2003 limit its ability to issue secured debt, including FMB,
subject to certain exceptions. Based upon applicable earnings coverage tests the
OE Companies could issue up to $3.4 billion of preferred stock (assuming no
additional debt was issued) as of March 31, 2004.
In October 2003, OE entered into a syndicated $125 million 364-day
revolving credit facility and a syndicated $125 million three-year revolving
credit facility. Combined with an existing syndicated $250 million two-year
facility for OE, maturing in May 2005 and bank facilities of $34 million, OE's
available credit facilities total $534 million, all of which were unused as of
March 31, 2004. These facilities are intended to provide liquidity to meet the
short-term working capital requirements of OE and its affiliates.
Borrowings under these facilities are conditioned on OE maintaining
compliance with certain financial covenants in the agreements. OE, under its
$125 million 364-day and $250 million two-year facilities, is required to
maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a
contractually-defined fixed charge coverage ratio of no less than 2 to 1. OE is
in compliance with these financial covenants. The ability to draw on these
facilities is also conditioned upon OE making certain representations and
warranties to the lending banks prior to drawing on its facilities, including a
representation that there has been no material adverse change in its business,
its condition (financial or otherwise), its results of operations, or its
prospects.
OE's primary credit facilities do not contain provisions, whereby its
ability to borrow would be restricted or denied, or repayment of outstanding
loans under the facilities accelerated, as a result of any change in the credit
ratings of OE by any of the nationally-recognized rating agencies. Borrowings
under the primary facilities do contain "pricing grids", whereby the cost of
funds borrowed under the facilities is related to the credit ratings of the
company borrowing the funds.
OE has the ability to borrow from its regulated affiliates and
FirstEnergy to meet its short-term working capital requirements. FESC
administers this money pool and tracks surplus funds of FirstEnergy and its
regulated subsidiaries, as well as proceeds available from bank borrowings.
Available bank borrowings include $1.75 billion from FirstEnergy's and OE's
revolving credit facilities. Companies receiving a loan under the money pool
agreements must repay the principal amount of such a loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from the pool and is based on the average
cost of funds available through the pool. The average interest rate for
borrowings in the first quarter of 2004 was 1.30%.
In March 2004, Penn completed an on-balance sheet, receivable
financing transaction which allows it to borrow up to $25 million. The borrowing
rate is based on bank commercial paper rates. Penn is required to pay an annual
facility fee of 0.40% on the entire finance limit. The facility was undrawn as
of March 31, 2004. This facility matures on March 29, 2005.
55
OE's access to capital markets and costs of financing are dependent
on the ratings of its securities and the securities of OE and FirstEnergy. The
ratings outlook on all of its securities is stable.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net use of cash for investing activities totaled $11 million in the
first quarter of 2004, compared to net cash provided by investing activities of
$106 million for the same period of 2003. The $117 million changes in funds from
investing activities resulted primarily from loan payments to associated
companies, offset in part by lower capital expenditures.
During the last three quarters of 2004, capital requirements for
property additions and capital leases are expected to be about $183 million,
including $46 million for nuclear fuel. OE has additional requirements of
approximately $68 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2004. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
As of March 31, 2004, OE has $278 million in deposits pledged as
collateral to secure reimbursement obligations related to certain letters of
credit supporting OE's obligations to lessors under the Beaver Valley Unit 2
sale and leaseback arrangements. The deposits had previously been classified as
a noncurrent asset in Other Property and Investments. OE expects to replace the
cash collateralized LOC with a structure that would not require cash collateral.
OE anticipates using the cash from the deposit to repay short term debt in the
third quarter of 2004 and for other general corporate purposes.
Off-Balance Sheet Arrangements
- ------------------------------
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, 2004, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $706
million.
Equity Price Risk
- -----------------
Included in OE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $218
million and $209 million as of March 31, 2004 and December 31, 2003,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $22 million reduction in fair value as of March 31, 2004.
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.
56
Regulatory Matters
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
Ohio
Beginning on January 1, 2001, OE's customers were able to choose their
electricity suppliers. 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 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
for OE customers), and the customer receives a generation charge from the
alternative supplier. OE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
As part of OE's transition plan, it is obligated to supply electricity
to customers who do not choose an alternative supplier. OE is also required to
provide 560 megawatts (MW) of low cost supply to unaffiliated alternative
suppliers who 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.
On October 21, 2003, the Ohio EUOC filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
57
o A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing OE's support of
energy efficiency and economic development efforts.
Under the first option, an auction would be conducted to secure
generation service for OE's customers. Beginning in 2006, customers would pay
market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of our support of energy-efficiency programs and the potential for
continuing the program to give preferred access to nonaffiliated entities to
generation capacity if shopping drops below 20%. Under the proposed plan, OE is
requesting:
o Extension of the transition cost amortization period from
2006 to 2007;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
o Ability to initiate a request to increase generation rates
under certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. Oral arguments were held before
the PUCO on April 21 and a decision is expected from the PUCO in the Spring of
2004.
Pennsylvania
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. Penn is
currently awaiting the PPUC to issue a final order in both matters. The order
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports.
On January 16, 2004, the PPUC initiated a formal investigation of
whether Penn's "service reliability performance deteriorated to a point below
the level of service reliability that existed prior to restructuring" in
Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony is
due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this
investigation and the ALJ has been directed to issue a Recommended Decision by
September 30, 2004, in order to allow the PPUC time to issue a Final Order by
year end of 2004. Penn is unable to predict the outcome of the investigation or
the impact of the PPUC order.
Regulatory Assets-
Regulatory assets are costs which have been authorized by the PUCO,
PPUC and the FERC, for recovery from customers in future periods and, without
such authorization, would have been charged to income when incurred. 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 plans.
The OE Companies' regulatory assets are as follows:
Regulatory Assets as of
---------------------------------------------------------
March 31, December 31,
Company 2004 2003
---------------------------------------------------------
(In millions)
OE......................... $1,348 $1,450
Penn....................... 15 28
---------------------------------------------------------
Consolidated Total...... $1,363 $1,478
===================================================================
58
Environmental Matters
Various federal, state and local authorities regulate OE with regard
to air and water quality and other environmental matters. 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 OE's earnings and competitive position to the extent that 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. Overall, OE believes it is in material compliance with
existing regulations but is unable to predict future change in regulatory
policies and what, if any, the effects of such change would be.
OE is required to meet federally approved 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 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. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on the OE
Companies' financial condition and results of operations. Management is unable
to predict the ultimate outcome of this matter and no liability has been accrued
as of March 31, 2004.
The OE Companies are complying with SO2 reduction requirements under
the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating
more electricity from lower-emitting plants, and/or using emission allowances.
NOx reductions required by the 1990 Amendments 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 OE Companies' 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the
District of Columbia based on a conclusion that such NOx emissions are
contributing significantly to ozone levels in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets. Pennsylvania submitted a SIP that required compliance with the NOx
budgets at the OE Companies' Pennsylvania facilities by May 1, 2003. Ohio
submitted a SIP that requires compliance with the NOx budgets at the OE
Companies' Ohio facilities by May 31, 2004. The OE Companies' facilities have
complied with the NOx budgets in 2003 and 2004, respectively.
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
59
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Regulatory Matters above). As many of these initiatives already
were in process and budgeted in 2004, FirstEnergy does not believe that any
incremental expenses associated with additional initiatives undertaken during
2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Legal Matters
Legal proceedings have been filed against FirstEnergy in connection
with, among other things, the restatements in August 2003 by FirstEnergy and its
Ohio utility subsidiaries of previously reported results, the August 14th power
outage described above, and the extended outage at the Davis-Besse Nuclear Power
Station. Depending upon the particular proceeding, the issues raised include
alleged violations of federal securities laws, breaches of fiduciary duties
under state law by FirstEnergy directors and officers, and damages as a result
of one or more of the noted events. The securities cases have been consolidated
into one action pending in federal court in Akron, Ohio. The derivative actions
filed in federal court likewise have been consolidated as a separate matter,
also in federal court in Akron. There also are pending derivative actions in
state court.
FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two regulatory proceedings initiated at the PUCO in response to complaints
alleging failure to provide reasonable and adequate service stemming primarily
from the August 14th power outage. FirstEnergy is vigorously defending these
actions, but cannot predict the outcome of any of these proceedings or whether
any further regulatory proceedings or legal actions may be instituted against
them. In particular, if FirstEnergy were ultimately determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on its financial condition and results of operations.
Various lawsuits, claims and proceedings related to OE's normal
business operations are pending against OE, the most significant of which are
described above.
Critical Accounting Policies
- ----------------------------
OE prepares its consolidated financial statements in accordance with
GAAP. Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of the OE
Companies' assets are subject to their own specific risks and uncertainties and
are regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting these specific factors. The OE Companies' more
significant accounting policies are described below.
Regulatory Accounting
The OE Companies are subject to regulation that sets the prices
(rates) they are permitted to charge their customers based on 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 -
$1.4 billion as of March 31, 2004. 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 electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
electricity sales to individual customers is based on meter readings, which
occur on a systematic basis throughout the month. At the end of each month,
electricity delivered to customers since the last meter reading is estimated and
a corresponding accrual for unbilled revenues is recognized. The determination
of unbilled revenues requires management to make estimates regarding electricity
available for retail load, transmission and distribution line losses,
consumption by customer class and electricity provided from alternative
suppliers.
60
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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.
Ohio Transition Cost Amortization
In connection with FirstEnergy's transition plan, the PUCO determined
allowable transition costs based on amounts recorded on OE's regulatory books.
These costs exceeded those deferred or capitalized on OE's balance sheet
prepared under GAAP since they included certain costs which have not yet been
incurred. OE uses an effective interest method for amortizing its transition
costs, often referred to as a "mortgage-style" amortization. The interest rate
under this method is equal to the rate of return authorized by the PUCO in the
transition plan for OE. In computing the transition cost amortization, OE
includes only the portion of the transition revenues associated with transition
costs included on the balance sheet prepared under GAAP. Revenues collected for
the off balance sheet costs and the return associated with these costs are
recognized as income when received.
Long-Lived Assets
In accordance with SFAS 144, the OE Companies periodically evaluate
their long-lived assets to determine whether conditions exist that would
indicate that the carrying value of an asset might 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 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
61
Nuclear Decommissioning
In accordance with SFAS 143, the OE Companies recognize an ARO for the
future decommissioning of their nuclear power plants. The ARO liability
represents an estimate of the fair value of the OE Companies' current obligation
related to nuclear decommissioning and the retirement of other assets. A fair
value measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. The OE Companies used an expected cash flow
approach (as discussed in FASB Concepts Statement No. 7) to measure the fair
value of the nuclear decommissioning ARO. This approach applies probability
weighting to discounted future cash flow scenarios that reflect a range of
possible outcomes. The scenarios consider settlement of the ARO at the
expiration of the nuclear power plants' current license and settlement based on
an extended license term.
New Accounting Standards and Interpretations
- --------------------------------------------
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, OE adopted FIN 46R for interests in VIEs commonly referred to
as special-purpose entities effective December 31, 2003 and for all other types
of entities effective March 31, 2004. Adoption of FIN 46R did not have a
material impact on OE's financial statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.
62
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
--------------------------
2004 2003
--------- --------
(In thousands)
OPERATING REVENUES.............................................................. $ 426,535 $ 419,771
---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 17,196 13,769
Purchased power.............................................................. 134,677 136,345
Nuclear operating costs...................................................... 32,715 55,361
Other operating costs........................................................ 64,027 61,899
---------- ----------
Total operation and maintenance expenses................................. 248,615 267,374
Provision for depreciation and amortization.................................. 61,776 51,357
General taxes................................................................ 38,818 39,713
Income taxes................................................................. 4,013 7,316
---------- ----------
Total operating expenses and taxes....................................... 353,222 365,760
---------- ----------
OPERATING INCOME................................................................ 73,313 54,011
OTHER INCOME.................................................................... 11,727 4,741
---------- ----------
INCOME BEFORE NET INTEREST CHARGES.............................................. 85,040 58,752
---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 32,211 40,640
Allowance for borrowed funds used during construction........................ (1,711) (2,167)
Other interest expense....................................................... 6,065 31
Subsidiary's preferred dividend requirements................................. -- 4,950
---------- ----------
Net interest charges..................................................... 36,565 43,454
---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 48,475 15,298
Cumulative effect of accounting change (Net of income taxes
of $30,168,000) (Note 2)...................................................... -- 42,378
---------- ----------
NET INCOME...................................................................... 48,475 57,676
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 1,744 (759)
---------- -----------
EARNINGS ON COMMON STOCK........................................................ $ 46,731 $ 58,435
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.
63
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
----------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $4,334,014 $4,232,335
Less-Accumulated provision for depreciation.................................... 1,880,144 1,857,588
----------- ----------
2,453,870 2,374,747
---------- ----------
Construction work in progress-
Electric plant............................................................... 95,271 159,897
Nuclear fuel................................................................. -- 21,338
---------- ----------
95,271 181,235
---------- ----------
2,549,141 2,555,982
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes..................................................... 584,950 605,915
Nuclear plant decommissioning trusts........................................... 332,303 313,621
Long-term notes receivable from associated companies........................... 97,212 107,946
Other.......................................................................... 17,818 23,636
---------- ----------
1,032,283 1,051,118
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 200 24,782
Receivables-
Customers.................................................................... 8,784 10,313
Associated companies......................................................... 43,741 40,541
Other (less accumulated provisions of $1,454,000 and $1,765,000, respectively,
for uncollectible accounts)................................................ 39,742 185,179
Notes receivable from associated companies..................................... 14,138 482
Materials and supplies, at average cost........................................ 52,971 50,616
Prepayments and other.......................................................... 2,616 4,511
---------- ----------
162,192 316,424
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 1,021,972 1,056,050
Goodwill....................................................................... 1,693,629 1,693,629
Property taxes................................................................. 77,122 77,122
Other.......................................................................... 23,599 23,123
---------- ----------
2,816,322 2,849,924
---------- ----------
$6,559,938 $6,773,448
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding.............................................. $1,281,962 $1,281,962
Accumulated other comprehensive income....................................... 7,405 2,653
Retained earnings............................................................ 485,944 494,212
---------- ----------
Total common stockholder's equity........................................ 1,775,311 1,778,827
Preferred stock not subject to mandatory redemption............................ 96,404 96,404
Long-term debt and other long-term obligations................................. 1,954,569 1,884,643
---------- ----------
3,826,284 3,759,874
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock........................... 379,924 387,414
Accounts payable-
Associated companies......................................................... 268,045 245,815
Other........................................................................ 7,499 7,342
Notes payable to associated companies.......................................... 16,203 188,156
Accrued taxes................................................................. 134,596 202,522
Accrued interest............................................................... 46,111 37,872
Lease market valuation liability............................................... 60,200 60,200
Other.......................................................................... 33,337 76,722
---------- ----------
945,915 1,206,043
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 485,976 486,048
Accumulated deferred investment tax credits.................................... 64,750 65,996
Asset retirement obligation.................................................... 259,049 254,834
Retirement benefits............................................................ 110,833 105,101
Lease market valuation liability............................................... 713,400 728,400
Other.......................................................................... 153,731 167,152
---------- ----------
1,787,739 1,807,531
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
---------- ----------
$6,559,938 $6,773,448
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these balance sheets.
64
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
----------------------------
2004 2003
--------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 48,475 $ 57,676
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization.............................. 61,776 51,357
Nuclear fuel and capital lease amortization.............................. 5,107 5,044
Other amortization....................................................... (4,723) (4,613)
Deferred operating lease costs, net...................................... (41,635) (41,603)
Deferred income taxes, net............................................... (2,793) 33,804
Amortization of investment tax credits................................... (1,246) (1,202)
Accrued retirement benefit obligations................................... 5,732 1,797
Accrued compensation, net................................................ 1,453 2,580
Cumulative effect of accounting change (Note 2).......................... -- (72,547)
Receivables.............................................................. 143,766 15,242
Materials and supplies................................................... (2,355) (128)
Accounts payable......................................................... 22,387 (44,129)
Accrued taxes............................................................ (67,926) 2,896
Accrued interest......................................................... 8,239 8,844
Prepayments and other current assets..................................... 1,895 1,772
Other.................................................................... (18,362) (11,970)
--------- ---------
Net cash provided from operating activities............................ 159,790 4,820
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt............................................................. 80,967 --
Short-term borrowings, net................................................. -- 33,245
Redemptions and Repayments-
Long-term debt............................................................. (7,985) (45,103)
Short-term borrowings, net................................................. (182,167) --
Dividend Payments-
Common stock............................................................... (55,000) --
Preferred stock............................................................ (1,744) (1,865)
--------- ---------
Net cash used for financing activities................................. (165,929) (13,723)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (17,868) (31,218)
Loans to associated companies, net........................................... (2,922) --
Investments in lessor notes.................................................. 20,965 19,071
Contributions to nuclear decommissioning trusts.............................. (7,256) (7,256)
Other........................................................................ (11,362) (1,250)
--------- ---------
Net cash used for investing activities................................. (18,443) (20,653)
--------- ---------
Net decrease in cash and cash equivalents....................................... (24,582) (29,556)
Cash and cash equivalents at beginning of period ............................... 24,782 30,382
--------- ---------
Cash and cash equivalents at end of period...................................... $ 200 $ 826
========= =========
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.
65
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, 2004, and the
related consolidated statements of income and cash flows for each of the
three-month periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change
in its method of accounting for asset retirement obligations as of January 1,
2003 as discussed in Note 1(F) to those consolidated financial statements and
the Company's change in its method of accounting for the consolidation of
variable interest entities as of December 31, 2003 as discussed in Note 7 to
those consolidated financial statements) dated February 25, 2004, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2003, 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 7, 2004
66
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI
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 2004 decreased to $47
million from $58 million in the first quarter of 2003. Earnings on common stock
in the first quarter of 2003 included an after-tax credit of $42 million from
the cumulative effect of an accounting change due to the adoption of SFAS 143.
Income before the cumulative effect increased to $48 million in the first
quarter of 2004 from $15 million in the first quarter of 2003.
Operating revenues increased by $7 million or 1.6% in the first
quarter of 2004 from the same period in 2003. Higher revenues resulted from a
$14 million (18.3%) increase in wholesale sales partially offset by a decrease
in kilowatt-hour sales to retail customers. The increase in wholesale sales
revenues (primarily to FES) was due to increased fossil generation (at the
Mansfield Plant) available for sale to FES. Electric generation services
provided by alternative suppliers as a percent of total sales deliveries in
CEI's franchise area increased to 42.5% in the first quarter of 2004 from 38.0%
in the first quarter of 2003, resulting in a 4.8% decrease in generation retail
sales and reducing generation sales revenue by $4 million.
Distribution deliveries increased 2.6% in the first quarter of 2004
compared to the corresponding quarter of 2003, with increases in all customer
sectors (residential, commercial and industrial). The $5 million decrease in
revenues from electricity throughput in the first quarter of 2004 from the same
quarter of the prior year was due to lower composite prices, offsetting the
effect of the higher distribution deliveries.
Under the Ohio transition plan, CEI provides incentives to customers
to encourage switching to alternative energy providers. These revenue reductions
are deferred for future recovery under the transition plan and do not materially
affect current period earnings. The change in shopping customer sales by class
(resulting in lower composite prices in 2004 compared to 2003) offset the effect
of increased shopping levels and resulted in a $3 million revenue increase.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2004 from the first quarter of 2003 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
---------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. (4.8)%
Wholesale............................... 10.0%
---------------------------------------------------
Total Electric Generation Sales........... 2.3%
===================================================
Distribution Deliveries:
Residential............................. 1.3%
Commercial.............................. 0.9%
Industrial.............................. 4.5%
---------------------------------------------------
Total Distribution Deliveries............. 2.6%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $13 million in the
first quarter of 2004 from the first quarter of 2003. The following table
presents changes from the prior year by expense category.
67
Operating Expenses and Taxes - Changes
----------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ 3
Purchased power ................................. (1)
Nuclear operating costs.......................... (23)
Other operating costs............................ 2
------------------------------------------------------------
Total operation and maintenance expenses....... (19)
Provision for depreciation and amortization...... 10
General taxes.................................... (1)
Income taxes..................................... (3)
-------------------------------------------------------------
Total operating expenses and taxes............. $(13)
=============================================================
Higher fuel costs in the first quarter of 2004, compared with the
first quarter of 2003, primarily resulted from increased fossil generation (up
64%). Lower purchased power costs reflect reduced kilowatt-hours purchased
offset in part by higher unit costs. Reductions in nuclear operating costs in
the first quarter of 2004, compared with the first quarter of 2003 were
primarily due to the reduction in incremental costs associated with the
Davis-Besse outage (see Davis-Besse Restoration). The increase in other
operating costs resulted in part from higher employee benefit costs.
The increase in depreciation and amortization charges in the first
quarter of 2004, compared with the first quarter of 2003, was primarily due to
increased amortization of regulatory assets ($6 million) and lower shopping
incentive deferrals ($3 million).
Income taxes in the first quarter of 2004 included credits from the
favorable resolution of certain tax matters that had been reserved in prior
periods, thus reducing CEI's reported effective income tax rate.
Other Income
The increase in other income was principally due to approximately $7
million of interest income from Shippingport which was consolidated into CEI as
of December 31, 2003.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $7
million in the first quarter of 2004 from the same quarter last year, reflecting
redemptions and refinancings since the end of the first quarter of 2003. CEI's
long-term debt redemptions of $8 million during the first quarter of 2004 are
expected to result in annualized savings of approximately $700,000.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded
an after-tax credit to net income of $42 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
resulted in a $73 million increase to income, or $42 million net of income
taxes.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements increased $3 million in the
first quarter of 2004, compared to the same period last year, due to an
adjustment that reduced costs in the first quarter of 2003.
Capital Resources and Liquidity
- -------------------------------
CEI's cash requirements in 2004 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, 2004, CEI had $200,000 of cash and cash equivalents,
compared with $25 million as of December 31, 2003 which included a portion of
the NRG settlement claim sold in January 2004. The major sources for changes in
these balances are summarized below.
68
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter of
2004, compared with the first quarter of 2003 were as follows:
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 72 $ 32
Working capital and other............ 88 (27)
-------------------------------------------------------------
Total................................ $160 $ 5
=============================================================
(1) Includes net income, depreciation and
amortization, deferred operating lease costs,
deferred income taxes, investment tax credits
and major noncash charges.
Net cash provided from operating activities increased $155 million in
the first quarter of 2004 from the first quarter of 2003 as a result of a $115
million increase from working capital and other changes and a $40 million
increase in cash earnings. The largest factor contributing to the change in
working capital was receiving the proceeds from the settlement of CEI's claim
against NRG, Inc. for the terminated sale of four power plants.
Cash Flows From Financing Activities
Net cash used for financing activities increased $152 million in the
first quarter of 2004 from the first quarter of 2003. The increase in funds used
for financing activities was the result of a $215 million net increase in
short-term borrowing repayments and a $55 million increase in common stock
dividends, partially offset by new financings of $81 million and reduced
security redemptions.
CEI had about $14 million of cash and temporary investments (which
include short-term notes receivable from associated companies) and approximately
$16 million of short-term indebtedness as of March 31, 2004. CEI had the
capability to issue $1.1 billion of additional first mortgage bonds on the basis
of property additions and retired bonds. CEI has no restrictions on the issuance
of preferred stock.
CEI has the ability to borrow from its regulated affiliates and
FirstEnergy to meet its short-term working capital requirements. FESC
administers this money pool and tracks surplus funds of FirstEnergy and its
regulated subsidiaries. Companies receiving a loan under the money pool
agreements must repay the principal amount, together with accrued interest,
within 364 days of borrowing the funds. The rate of interest is the same for
each company receiving a loan from the pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in
the first quarter of 2004 was 1.30%.
CEI's access to capital markets and costs of financing are dependent
on the ratings of its securities and that of FirstEnergy. The ratings outlook on
all of its securities is stable.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net cash used for investing activities decreased $2 million in the
first quarter of 2004 from the first quarter of 2003 and was primarily due to
lower capital expenditures.
69
During the last three quarters of 2004, capital requirements for
property additions are expected to be about $106 million, including $27 million
for nuclear fuel. CEI has additional requirements of approximately $281 million
to meet sinking fund requirements for preferred stock and maturing long-term
debt during the remainder of 2004.
Off-Balance Sheet Arrangements
- ------------------------------
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, 2004, the present value of these sale and leaseback operating
lease commitments, net of trust investments, total $109 million.
CEI sells substantially all of its retail customer receivables to CFC,
a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to
a trust (a "qualified special purpose entity" under SFAS 140) under an
asset-backed securitization agreement. This arrangement provided $132 million of
off-balance sheet financing as of March 31, 2004.
As of March 31, 2004, off-balance sheet arrangements include certain
statutory business trusts created by CEI to issue trust preferred securities in
the amount of $100 million. These trusts were included in the consolidated
financial statements of FirstEnergy prior to the adoption of FIN 46R effective
December 31, 2003, but have subsequently been deconsolidated under FIN 46R (see
Note 2 - Variable Interest Entities). The deconsolidation under FIN 46R did not
result in any change in outstanding debt.
Equity Price Risk
- -----------------
Included in CEI's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $202
million and $188 million as of March 31, 2004 and December 31, 2003,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $20 million reduction in fair value as of March 31, 2004.
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 system, which remains regulated.
Customer rates were restructured into separate components to support customer
choice. 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 FERC for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. CEI's regulatory
assets as of March 31, 2004 and December 2003 were $1.02 billion and $1.06
billion, respectively. All of CEI's regulatory assets are expected to continue
to be recovered under the provisions of the transition plan.
As part of CEI's transition plan, it is obligated to supply
electricity to customers who do not choose an alternative supplier. CEI is also
required to provide 400 MW of low cost supply to unaffiliated alternative
suppliers who 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.
On October 21, 2003, the Ohio EUOC filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
70
o A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing CEI's support of
energy efficiency and economic development efforts.
Under the first option, an auction would be conducted to secure
generation service for CEI's customers. Beginning in 2006, customers would pay
market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of CEI's support of energy-efficiency programs and the potential for
continuing the program to give preferred access to nonaffiliated entities to
generation capacity if shopping drops below 20%. Under the proposed plan, CEI is
requesting:
o Extension of the transition cost amortization period from
2008 to mid-2009;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
o Ability to initiate a request to increase generation rates
under certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. Oral arguments were held before
the PUCO on April 21 and a decision is expected from the PUCO in the Spring of
2004.
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional material expenditures.
71
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
Davis-Besse Restoration
On April 30, 2002, the 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 was 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. This process led to the
NRC's March 8, 2004 approval of Davis-Besse's restart.
Restart activities included both hardware and management issues. In
addition to refurbishment and installation work at the plant, FENOC made
significant management and human performance changes with the intent of
enhancing the proper safety culture throughout the workforce. The focus of
activities in the first quarter of 2004 involved management and human
performance issues. As a result, incremental maintenance costs declined in the
first quarter of 2004 compared to the same period in 2003 as emphasis shifted to
performance issues; however, replacement power costs were higher in the first
quarter of 2004. The plant's generating equipment was tested in March in
preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed
generating electricity at 100% power.
Incremental costs associated with the extended Davis-Besse outage
(CEI's share - 51.38%) for the first quarter of 2004 and 2003 were as follows:
Three Months Ended
March 31,
------------------ Increase
Costs of Davis-Besse Extended Outage 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Incremental Expense
Replacement power................. $64 $52 $ 12
Maintenance....................... 1 36 (35)
- --------------------------------------------------------------------------------
Total......................... $65 $88 $(23)
================================================================================
Incremental Net of Tax Expense...... $38 $52 $(14)
================================================================================
Environmental Matters
Various federal, state and local authorities regulate CEI with regard
to air and water quality and other environmental matters. 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 CEI's earnings and competitive position to the extent that 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. Overall, CEI believes it is in material compliance with
existing regulations but is unable to predict future change in regulatory
policies and what, if any, the effects of such change would be.
CEI is required to meet federally approved 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 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.
CEI is complying with SO2 reduction requirements under the Clean Air
Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity
from lower-emitting plants, and/or using emission allowances. NOx reductions
required by the 1990 Amendments 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
CEI's 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the District
of Columbia based on a conclusion that such NOx emissions are contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets.
Pennsylvania submitted a SIP that required compliance with the NOx budgets at
CEI's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires
compliance with the NOx budgets at CEI's Ohio facilities by May 31, 2004. CEI's
facilities have complied with the NOx budgets in 2003 and 2004, respectively.
72
CEI has been named as a 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, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheets, based on estimates of the total costs of cleanup,
CEI's proportionate responsibility for such costs and the financial ability of
other nonaffiliated entities to pay. CEI has accrued liabilities aggregating
approximately $2.4 million as of March 31, 2004. CEI accrues environmental
liabilities only when it can conclude that it is probable that an obligation for
such costs exists and can reasonably determine the amount of such costs.
Unasserted claims are reflected in CEI's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Reliability Initiatives above). As many of these initiatives
already were in process and budgeted in 2004, FirstEnergy does not believe that
any incremental expenses associated with additional initiatives undertaken
during 2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
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 herein.
FENOC received a subpoena in late 2003 from a grand jury sitting in
the United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis-Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks among other things, suspension of the Davis-Besse operating
license. If it were ultimately determined that FirstEnergy has legal liability
or is otherwise made subject to enforcement action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on CEI's financial condition and results of operations.
Legal proceedings have been filed against FirstEnergy in connection
with, among other things, the restatements in August 2003 by FirstEnergy and its
Ohio utility subsidiaries of previously reported results, the August 14th power
outage described above, and the extended outage at the Davis-Besse Nuclear Power
Station. Depending upon the particular proceeding, the issues raised include
alleged violations of federal securities laws, breaches of fiduciary duties
under state law by FirstEnergy directors and officers, and damages as a result
of one or more of the noted events. The securities cases have been consolidated
into one action pending in federal court in Akron, Ohio. The derivative actions
filed in federal court likewise have been consolidated as a separate matter,
also in federal court in Akron. There are also pending derivative actions in
state court.
73
FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two regulatory proceedings initiated at the PUCO in response to complaints
alleging failure to provide reasonable and adequate service stemming primarily
from the August 14th power outage. FirstEnergy is vigorously defending these
actions, but cannot predict the outcome of any of these proceedings or whether
any further regulatory proceedings or legal actions may be instituted against
them. In particular, if FirstEnergy were ultimately determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on CEI's financial condition and results of operations.
Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outage. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed.
Critical Accounting Policies
CEI prepares its consolidated financial statements in accordance with
GAAP. Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect 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 these
specific factors. CEI's more significant accounting policies are described
below.
Regulatory Accounting
CEI is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on 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 - $1.02 billion as of March 31, 2004. 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 electricity that has been delivered to customers but not yet billed
through the end of the accounting period. The determination of electricity sales
to individual customers is based on meter readings, which occur on a systematic
basis throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled revenues is recognized. The determination of unbilled revenues
requires management to make estimates regarding electricity available for retail
load, transmission and distribution line losses, consumption by customer class
and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
74
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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.
Ohio Transition Cost Amortization
In connection with FirstEnergy's transition plan, the PUCO determined
allowable transition costs based on amounts recorded on CEI's regulatory books.
These costs exceeded those deferred or capitalized on CEI's balance sheet
prepared under GAAP since they included certain costs which have not yet been
incurred or that were recognized on the regulatory financial statements (fair
value purchase accounting adjustments). CEI uses an effective interest method
for amortizing its transition costs, often referred to as a "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for CEI. In computing the
transition cost amortization, CEI includes only the portion of the transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP. Revenues collected for the off balance sheet costs and the return
associated with these costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS 144, CEI periodically evaluates its long-lived
assets to determine whether conditions exist that would indicate that the
carrying value of an asset might 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 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, CEI recognizes an ARO for the future
decommissioning of its nuclear power plants. The ARO liability represents an
estimate of the fair value of CEI's current obligation related to nuclear
decommissioning and the retirement of other assets. A fair value measurement
inherently involves uncertainty in the amount and timing of settlement of the
liability. CEI used an expected cash flow approach (as discussed in FASB
Concepts Statement No. 7) to measure the fair value of the nuclear
decommissioning ARO. This approach applies probability weighting to discounted
future cash flow scenarios that reflect a range of possible outcomes. The
scenarios consider settlement of the ARO at the expiration of the nuclear power
plants' current license and settlement based on an extended license term.
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 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), the goodwill is tested for
impairment. If impairment were to be indicated CEI would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill. CEI's annual review was completed in the
third quarter of 2003, with no impairment of goodwill indicated. 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 CEI's future evaluations of goodwill. As of March
31, 2004, CEI had $1.7 billion of goodwill.
75
New Accounting Standards and Interpretations
- --------------------------------------------
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, CEI adopted FIN 46R for interests in VIEs commonly referred to
as special-purpose entities effective December 31, 2003 and for all other types
of entities effective March 31, 2004. Adoption of FIN 46R did not have a
material impact on CEI's financial statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.
76
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2004 2003
-------- --------
Restated
(See Note 2)
(In thousands)
OPERATING REVENUES.............................................................. $235,398 $231,822
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 10,214 8,406
Purchased power.............................................................. 82,408 74,251
Nuclear operating costs...................................................... 42,692 64,555
Other operating costs........................................................ 36,208 32,932
-------- --------
Total operation and maintenance expenses................................. 171,522 180,144
Provision for depreciation and amortization.................................. 40,689 35,640
General taxes................................................................ 14,300 15,008
Income taxes (benefit)....................................................... (1,578) (4,291)
-------- --------
Total operating expenses and taxes....................................... 224,933 226,501
-------- --------
OPERATING INCOME................................................................ 10,465 5,321
-------- --------
OTHER INCOME.................................................................... 5,833 3,100
-------- --------
INCOME BEFORE NET INTEREST CHARGES.............................................. 16,298 8,421
-------- --------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 9,461 10,888
Allowance for borrowed funds used during construction........................ (1,400) (1,306)
Other interest expense (credit).............................................. 706 (532)
-------- --------
Net interest charges..................................................... 8,767 9,050
-------- --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 7,531 (629)
Cumulative effect of accounting change (net of income taxes
of $18,201,000) (Note 2)..................................................... -- 25,550
-------- --------
NET INCOME...................................................................... 7,531 24,921
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 2,211 2,205
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 5,320 $ 22,716
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to The
Toledo Edison Company are an integral part of these statements.
77
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service.................................................................... $1,801,162 $1,714,870
Less-Accumulated provision for depreciation................................... 733,161 721,754
---------- ----------
1,068,001 993,116
---------- ----------
Construction work in progress-
Electric plant.............................................................. 66,499 125,051
Nuclear fuel................................................................ -- 20,189
---------- ----------
66,499 145,240
---------- ----------
1,134,500 1,138,356
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes.................................................... 190,658 200,938
Nuclear plant decommissioning trusts.......................................... 255,996 240,634
Long-term notes receivable from associated companies.......................... 163,961 163,626
Other......................................................................... 2,326 2,119
---------- ----------
612,941 607,317
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents..................................................... 16 2,237
Receivables-
Customers................................................................... 4,876 4,083
Associated companies........................................................ 21,982 29,158
Other....................................................................... 734 14,386
Notes receivable from associated companies.................................... 16,376 19,316
Materials and supplies, at average cost....................................... 36,581 35,147
Prepayments and other........................................................ 3,320 6,704
---------- ----------
83,885 111,031
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................. 432,399 459,040
Goodwill...................................................................... 504,522 504,522
Property taxes................................................................ 24,443 24,443
Other......................................................................... 10,902 10,689
---------- ----------
972,266 998,694
---------- ----------
$2,803,592 $2,855,398
========== ==========
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 income...................................... 15,023 11,672
Retained earnings........................................................... 118,940 113,620
---------- ----------
Total common stockholder's equity......................................... 758,192 749,521
Preferred stock not subject to mandatory redemption........................... 126,000 126,000
Long-term debt................................................................ 274,595 270,072
---------- ----------
1,158,787 1,145,593
CURRENT LIABILITIES:
Currently payable long-term debt.............................................. 335,950 283,650
Short-term borrowings......................................................... -- 70,000
Accounts payable-
Associated companies........................................................ 126,835 132,876
Other....................................................................... 2,784 2,816
Notes payable to associated companies......................................... 262,654 285,953
Accrued taxes................................................................ 41,518 55,604
Accrued interest.............................................................. 10,132 12,412
Lease market valuation liability.............................................. 24,600 24,600
Other......................................................................... 46,771 37,299
---------- ----------
851,244 905,210
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes............................................. 204,108 201,954
Accumulated deferred investment tax credits................................... 26,668 27,200
Retirement benefits........................................................... 49,291 47,006
Asset retirement obligation................................................... 184,882 181,839
Lease market valuation liability.............................................. 286,450 292,600
Other......................................................................... 42,162 53,996
---------- ----------
793,561 804,595
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)...............................
---------- ----------
$2,803,592 $2,855,398
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these balance sheets.
78
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
--------------------------
2004 2003
-------- --------
Restated
(See Note 2)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 7,531 $ 24,921
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization.............................. 40,689 35,640
Nuclear fuel and capital lease amortization.............................. 5,506 2,768
Deferred operating lease costs, net...................................... (7,692) (7,672)
Deferred income taxes, net............................................... (1,499) 19,130
Amortization of investment tax credits................................... (532) (514)
Accrued retirement benefit obligation.................................... 2,285 771
Accrued compensation, net................................................ (733) (1,865)
Cumulative effect of accounting change (Note 2).......................... -- (43,751)
Receivables.............................................................. 20,035 12,249
Materials and supplies................................................... (1,434) (727)
Accounts payable......................................................... (6,074) (53,917)
Accrued taxes............................................................ (14,085) 6,281
Accrued interest......................................................... (2,280) (2,326)
Prepayments and other current assets..................................... 3,384 (5,121)
Other.................................................................... 79 (15,438)
-------- --------
Net cash provided from (used for) operating activities................. 45,180 (29,571)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt............................................................. 73,000 --
Short-term borrowings, net................................................. -- 98,392
Redemptions and Repayments-
Long-term debt............................................................. (15,000) (73,600)
Short-term borrowings, net................................................. (93,299) --
Dividend Payments-
Preferred stock............................................................ (2,211) (2,211)
-------- --------
Net cash provided from (used for) financing activities................. (37,510) 22,581
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (8,440) (17,622)
Loans from (to) associated companies, net.................................... 2,606 (4,445)
Investment in lessor notes................................................... 10,280 17,628
Contributions to nuclear decommissioning trust............................... (7,135) (7,135)
Other........................................................................ (7,202) (679)
-------- --------
Net cash used for investing activities................................. (9,891) (12,253)
-------- --------
Net decrease in cash and equivalents............................................ (2,221) (19,243)
Cash and cash equivalents at beginning of period................................ 2,237 20,688
-------- --------
Cash and cash equivalents at end of period...................................... $ 16 $ 1,445
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these statements.
79
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, 2004, and the related
consolidated statements of income and cash flows for each of the three-month
periods ended March 31, 2004 and 2003. 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 2 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the three-month period ended March 31, 2003.
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, 2003, 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 (which contained references to the Company's change
in its method of accounting for asset retirement obligations as of January 1,
2003 as discussed in Note 1(F) to those consolidated financial statements and
the Company's change in its method of accounting for the consolidation of
variable interest entities as of December 31, 2003 as discussed in Note 7 to
those consolidated financial statements) dated February 25, 2004, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2003, 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 7, 2004
80
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE
conducts business in northwestern 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
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.
Restatements of Previously Reported Quarterly Results
- -----------------------------------------------------
As discussed in Note 2 to the Consolidated Financial Statements, TE's
quarterly results for the first quarter of 2003 have been restated to correct
the amounts reported for operating expenses and interest charges. TE's costs
which were originally recorded as operating expenses and should have been
capitalized to construction were $0.4 million ($0.2 million after-tax), in the
first quarter of 2003. In addition, TE's interest expense was overstated by $0.9
million ($0.5 million after-tax) in the first quarter of 2003. The impact of
these adjustments was not material to TE's Consolidated Balance Sheets or
Consolidated Statements of Cash Flows for any quarter of 2003.
Results of Operations
- ---------------------
Earnings on common stock in the first quarter of 2004 decreased to $5
million from $23 million in the first quarter of 2003. Earnings on common stock
in the first quarter of 2003 included an after-tax credit of $26 million from
the cumulative effect of an accounting change due to the adoption of SFAS 143.
Income before the cumulative effect increased to $8 million in the first quarter
of 2004 from a loss of $629,000 in the first quarter of 2003.
Operating revenues increased by $4 million or 1.5% in the first
quarter of 2004 from the same period in 2003. Higher revenues resulted from an
$11 million (20.3%) increase in wholesale sales partially offset by a decrease
in retail sales revenues. The increase in sales revenues from wholesale
customers (primarily to FES) was due to increased fossil generation (at the
Mansfield Plant) available for sale to FES. Electric generation services
provided by alternative suppliers as a percent of total sales delivered in TE's
franchise area increased to 23.7% in the first quarter of 2004 from 22% in the
first quarter of 2003, resulting in a 4.0% decrease in TE's retail generation
sales and a $3 million reduction in revenues.
Distribution deliveries decreased 1.8% in the first quarter of 2004
compared to the corresponding quarter of 2003, with an increase in the
industrial customer sector more than offset by reductions in the residential and
commercial customer sectors. The $3 million decrease in revenues from
electricity throughput in the first quarter of 2004 from the same quarter of the
prior year was due to lower composite prices and reduced distribution
deliveries.
Under the Ohio transition plan, TE provides incentives to customers to
encourage switching to alternative energy providers. These revenue reductions
are deferred for future recovery under the transition plan and do not materially
affect current period earnings. The change in revenue from shopping credits was
relatively flat in the first quarter of 2004 compared with the corresponding
period of 2003.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2004 from the first quarter of 2003 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
----------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (4.0)%
Wholesale............................. 21.9%
----------------------------------------------------
Total Electric Generation Sales........... 6.5%
====================================================
Distribution Deliveries:
Residential............................. (5.0)%
Commercial.............................. (3.6)%
Industrial.............................. 1.2%
----------------------------------------------------
Total Distribution Deliveries............. (1.8)%
====================================================
81
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $2 million in the
first quarter of 2004 from the first quarter of 2003. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
-----------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ 2
Purchased power.................................. 8
Nuclear operating costs.......................... (22)
Other operating costs............................ 3
------------------------------------------------------------
Total operation and maintenance expenses....... (9)
Provision for depreciation and amortization...... 5
General taxes.................................... (1)
Income taxes..................................... 3
------------------------------------------------------------
Total operating expenses and taxes............. $(2)
=============================================================
Higher fuel costs in the first quarter of 2004, compared with the
first quarter of 2003, primarily resulted from increased fossil generation (up
54%). Higher purchased power costs reflect additional kilowatt-hours purchased
and higher unit costs. Reductions in nuclear operating costs in the first
quarter of 2004, compared with the first quarter of 2003, were primarily due to
the reduction in incremental costs associated with the Davis-Besse outage (see
Davis-Besse Restoration). The increase in other operating costs resulted from
higher energy delivery costs related to increased tree trimming activities.
The increase in depreciation and amortization charges of $5 million in
the first quarter of 2004, compared with the first quarter of 2003, was
primarily due to increased amortization of regulatory assets.
Other Income
Other income increased by $3 million in the first quarter of 2004
compared to the same period of 2003 primarily due to the absence of 2003 costs
related to closing Acme in Toledo, Ohio.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $283,000
in the first quarter of 2004 from the same quarter last year, reflecting
redemptions and refinancings since the end of the first quarter of 2003. TE's
long-term debt redemptions of $15 million during the first quarter of 2004 are
expected to result in annualized savings of approximately $1 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 $26 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 $44
million increase to income, or $26 million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
TE's cash requirements in 2004 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, 2004, TE had approximately $16,000 of cash and cash
equivalents, compared with $2 million as of December 31, 2003. 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
2004, compared with the first quarter of 2003 were as follows:
82
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 45 $ 29
Working capital and other............ -- (59)
-------------------------------------------------------------
Total................................ $45 $(30)
=============================================================
(1) Includes net income, depreciation and amortization, deferred
operating lease costs, deferred income taxes, investment tax
credits and major noncash charges.
Net cash provided from operating activities increased $75 million in
the first quarter of 2004 from the first quarter of 2003 as a result of a $59
million increase from working capital and other changes and a $16 million
increase in cash earnings. The largest factor contributing to the change in
working capital was a $48 million change in accounts payable. The increase from
the change in working capital also included receiving $12 million in proceeds
from the settlement of TE's claim against NRG, Inc. for the terminated sale of
its Bay Shore Plant.
Cash Flows From Financing Activities
Net cash used for financing activities was $38 million in the first
quarter of 2004 compared to $23 million provided from financing activities in
the first quarter of 2003. The repayments and redemptions of debt in the first
quarter of 2004 exceeded proceeds from issuing new long-term debt by $35
million. In the first quarter of 2003, short-term borrowings exceeded repayments
of long-term debt by $25 million.
TE had $16 million of cash and temporary investments (which include
short-term notes receivable from associated companies) and $263 million of
short-term indebtedness as of March 31, 2004. TE is currently precluded from
issuing first mortgage bonds or preferred stock based upon applicable earnings
coverage tests.
TE has the ability to borrow from its regulated affiliates and
FirstEnergy to meet its short-term working capital requirements. FESC
administers this money pool and tracks surplus funds of FirstEnergy and its
regulated subsidiaries. Companies receiving a loan under the money pool
agreements must repay the principal amount, together with accrued interest,
within 364 days of borrowing the funds. The rate of interest is the same for
each company receiving a loan from the pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in
the first quarter of 2004 was 1.30%.
TE's access to capital markets and costs of financing are dependent on
the ratings of its securities and that of our holding company, FirstEnergy. The
ratings outlook on all of its securities is stable.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net cash used for investing activities decreased $2 million in the
first quarter of 2004 from the first quarter of 2003 and was primarily due to
lower capital expenditures.
During the last three quarters of 2004, capital requirements for
property additions are expected to be about $42 million. TE has additional
requirements of approximately $215 million to meet sinking fund requirements for
preferred stock and maturing long-term debt during the remainder of 2004. The
cash requirements are expected to be satisfied from internal cash and short-term
arrangements.
83
Off-Balance Sheet Arrangements
- ------------------------------
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, 2004, the present value of these sale
and leaseback operating lease commitments, net of trust investments, total $595
million.
TE sells substantially all of its retail customer receivables to CFC,
a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to
a trust (a "qualified special purpose entity" under SFAS 140) under an
asset-backed securitization agreement. This arrangement provided $68 million of
off-balance sheet financing as of March 31, 2004.
Equity Price Risk
- -----------------
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $156
million and $145 million as of March 31, 2004 and December 31, 2003,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $16 million reduction in fair value as of March 31, 2004.
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 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 PUCO and
the FERC for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. TE's regulatory
assets as of March 31, 2004 and December 2003 are $432 million and $459 million,
respectively. All of TE's regulatory assets are expected to continue to be
recovered under the provisions of the transition plan.
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
provide 160 megawatts (MW) of low cost supply to unaffiliated alternative
suppliers who 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.
On October 21, 2003, the Ohio EUOC filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing TE's support of
energy efficiency and economic development efforts.
Under the first option, an auction would be conducted to secure
generation service for TE's customers. Beginning in 2006, customers would pay
market prices for generation as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
84
conducted annually to ensure that customers pay the lowest available prices;
extension of TE's support of energy-efficiency programs and the potential for
continuing the program to give preferred access to nonaffiliated entities to
generation capacity if shopping drops below 20%. Under the proposed plan, TE is
requesting:
o Extension of the transition cost amortization period from
mid-2007 to mid-2008;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
o Ability to initiate a request to increase generation rates
under certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. Oral arguments were held before
the PUCO on April 21 and a decision is expected from the PUCO in the Spring of
2004.
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
85
Davis-Besse Restoration
On April 30, 2002, the 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 was 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. This process led to the
NRC's March 8, 2004 approval of Davis-Besse's restart.
Restart activities included both hardware and management issues. In
addition to refurbishment and installation work at the plant, FENOC made
significant management and human performance changes with the intent of
enhancing the proper safety culture throughout the workforce. The focus of
activities in the first quarter of 2004 involved management and human
performance issues. As a result, incremental maintenance costs declined in the
first quarter of 2004 compared to the same period in 2003 as emphasis shifted to
performance issues; however, replacement power costs were higher in the first
quarter of 2004. The plant's generating equipment was tested in March in
preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed
generating electricity at 100% power.
Incremental costs associated with the extended Davis-Besse outage
(TE's share - 48.62%) for the first quarter of 2004 and 2003 were as follows:
Three Months Ended
March 31,
------------------- Increase
Costs of Davis-Besse Extended Outage 2004 2003 (Decrease)
------------------------------------------------------------------------------
(In millions)
Incremental Expense
Replacement power................. $64 $52 $ 12
Maintenance....................... 1 36 (35)
-----------------------------------------------------------------------------
Total......................... $65 $88 $(23)
=============================================================================
Incremental Net of Tax Expense...... $38 $52 $(14)
==============================================================================
Environmental Matters
Various federal, state and local authorities regulate TE with regard
to air and water quality and other environmental matters. 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 TE's earnings and competitive position to the extent that 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. Overall, TE believes it is in material compliance with
existing regulations but is unable to predict future change in regulatory
policies and what, if any, the effects of such change would be.
TE is required to meet federally approved 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 EPA has an interim enforcement policy for SO2 regulations in Ohio
that allows for compliance based on a 30-day averaging period. TE cannot predict
what action the EPA may take in the future with respect to the interim
enforcement policy.
TE is complying with SO2 reduction requirements under the Clean Air
Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity
from lower-emitting plants, and/or using emission allowances. NOx reductions
required by the 1990 Amendments 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
TE's 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the District
of Columbia based on a conclusion that such NOx emissions are contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets.
Pennsylvania submitted a SIP that required compliance with the NOx budgets at
TE's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires
compliance with the NOx budgets at TE's Ohio facilities by May 31, 2004. TE's
facilities have complied with the NOx budgets in 2003 and 2004, respectively.
TE has been named as a 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, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheets, based on estimates of the total costs of cleanup,
TE's proportionate responsibility for such costs and the financial ability of
other nonaffiliated entities to pay. TE has accrued liabilities aggregating
86
approximately $0.2 million as of March 31, 2004. TE accrues environmental
liabilities only when it can conclude that it is probable that an obligation for
such costs exists and can reasonably determine the amount of such costs.
Unasserted claims are reflected in TE's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Reliability Initiatives above). As many of these initiatives
already were in process and budgeted in 2004, FirstEnergy does not believe that
any incremental expenses associated with additional initiatives undertaken
during 2004 will have a material effect on its operations or financial results.
First Energy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Legal Matters
Various lawsuits, claims and proceedings related to TE's normal
business operations are pending against TE, the most significant of which are
described herein.
FENOC received a subpoena in late 2003 from a grand jury sitting in
the United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks among other things, suspension of the Davis-Besse operating
license. If it were ultimately determined that FirstEnergy has legal liability
or is otherwise made subject to enforcement action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on TE's financial condition and results of operations.
Legal proceedings have been filed against FirstEnergy in connection
with, among other things, the restatements in August 2003 by FirstEnergy and its
Ohio utility subsidiaries of previously reported results, the August 14th power
outage described above, and the extended outage at the Davis-Besse Nuclear Power
Station. Depending upon the particular proceeding, the issues raised include
alleged violations of federal securities laws, breaches of fiduciary duties
under state law by FirstEnergy directors and officers, and damages as a result
of one or more of the noted events. The securities cases have been consolidated
into one action pending in federal court in Akron, Ohio. The derivative actions
filed in federal court likewise have been consolidated as a separate matter,
also in federal court in Akron. There are also pending derivative actions in
state court.
FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two regulatory proceedings initiated at the PUCO in response to complaints
alleging failure to provide reasonable and adequate service stemming primarily
from the August 14th power outage. FirstEnergy is vigorously defending these
actions, but cannot predict the outcome of any of these proceedings or whether
any further regulatory proceedings or legal actions may be instituted against
them. In particular, if FirstEnergy were ultimately determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on TE's financial condition and results of operations.
87
Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outage. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed.
Critical Accounting Policies
- ----------------------------
TE prepares its consolidated financial statements in accordance with
GAAP. Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect 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 these
specific factors. TE's more significant accounting policies are described below.
Regulatory Accounting
TE is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on 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 - $432 million as of March 31, 2004. 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 electricity that has been delivered to customers but not yet billed
through the end of the accounting period. The determination of electricity sales
to individual customers is based on meter readings, which occur on a systematic
basis throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled revenues is recognized. The determination of unbilled revenues
requires management to make estimates regarding electricity available for retail
load, transmission and distribution line losses, consumption by customer class
and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
88
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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.
Ohio Transition Cost Amortization
In connection with FirstEnergy's transition plan, the PUCO determined
allowable transition costs based on amounts recorded on TE's regulatory books.
These costs exceeded those deferred or capitalized on TE's balance sheet
prepared under GAAP since they included certain costs which have not yet been
incurred or that were recognized on the regulatory financial statements (fair
value purchase accounting adjustments). TE uses an effective interest method for
amortizing its transition costs, often referred to as a "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for TE. In computing the
transition cost amortization, TE includes only the portion of the transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP. Revenues collected for the off balance sheet costs and the return
associated with these costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS 144, TE periodically evaluates its long-lived
assets to determine whether conditions exist that would indicate that the
carrying value of an asset might 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 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, TE recognizes an ARO for the future
decommissioning of its nuclear power plants. The ARO liability represents an
estimate of the fair value of TE's current obligation related to nuclear
decommissioning and the retirement of other assets. A fair value measurement
inherently involves uncertainty in the amount and timing of settlement of the
liability. TE used an expected cash flow approach (as discussed in FASB Concepts
Statement No. 7) to measure the fair value of the nuclear decommissioning ARO.
This approach applies probability weighting to discounted future cash flow
scenarios that reflect a range of possible outcomes. The scenarios consider
settlement of the ARO at the expiration of the nuclear power plants' current
license and settlement based on an extended license term.
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
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), the goodwill is tested for impairment. If
impairment were to be indicated, TE would recognize a loss - calculated as the
difference between the implied fair value of its goodwill and the carrying value
of the goodwill. TE's annual review was completed in the third quarter of 2003,
with no impairment of goodwill indicated. 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
TE's future evaluations of goodwill. As of March 31, 2004, TE had $505 million
of goodwill.
89
New Accounting Standards and Interpretations
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, TE adopted FIN 46R for interests in VIEs commonly referred to
as special-purpose entities effective December 31, 2003 and for all other types
of entities effective March 31, 2004. Adoption of FIN 46R did not have a
material impact on TE's financial statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.
90
PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2004 2003
--------- --------
(In thousands)
OPERATING REVENUES.............................................................. $142,623 $128,343
-------- --------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 6,206 4,713
Purchased power.............................................................. 48,508 44,066
Nuclear operating costs...................................................... 18,623 46,929
Other operating costs........................................................ 13,685 16,550
-------- --------
Total operation and maintenance expenses................................. 87,022 112,258
Provision for depreciation and amortization.................................. 13,438 13,265
General taxes................................................................ 6,634 6,179
Income taxes (benefit)....................................................... 15,038 (1,479)
-------- --------
Total operating expenses and taxes....................................... 122,132 130,223
-------- --------
OPERATING INCOME (LOSS)......................................................... 20,491 (1,880)
OTHER INCOME.................................................................... 982 561
-------- --------
INCOME (LOSS) BEFORE NET INTEREST CHARGES....................................... 21,473 (1,319)
-------- --------
NET INTEREST CHARGES:
Interest expense............................................................. 2,725 4,064
Allowance for borrowed funds used during construction........................ (922) (629)
-------- --------
Net interest charges..................................................... 1,803 3,435
-------- --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 19,670 (4,754)
Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 2) -- 10,618
-------- --------
NET INCOME...................................................................... 19,670 5,864
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 640 912
-------- --------
EARNINGS ON COMMON STOCK........................................................ $ 19,030 $ 4,952
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an
integral part of these statements.
91
PENNSYLVANIA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service........................................................................ $820,643 $808,637
Less-Accumulated provision for depreciation....................................... 332,363 324,710
-------- --------
488,280 483,927
-------- --------
Construction work in progress-
Electric plant................................................................. 69,521 68,091
Nuclear fuel................................................................... 360 360
-------- --------
69,881 68,451
-------- --------
558,161 552,378
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts ............................................. 137,840 133,867
Long-term notes receivable from associated companies.............................. 33,136 39,179
Other............................................................................. 836 2,195
-------- --------
171,812 175,241
-------- --------
CURRENT ASSETS:
Cash and cash equivalents......................................................... 40 40
Notes receivable from associated companies........................................ 6,558 399
Receivables-
Customers (less accumulated provisions of $816,000 and $769,000,
respectively, for uncollectible accounts).................................... 46,129 44,861
Associated companies........................................................... 24,492 24,965
Other.......................................................................... 466 1,047
Materials and supplies, at average cost........................................... 34,993 33,918
Prepayments....................................................................... 22,716 9,383
-------- --------
135,394 114,613
-------- --------
DEFERRED CHARGES:
Regulatory assets................................................................. 15,155 27,513
Other............................................................................. 9,348 9,634
-------- --------
24,503 37,147
-------- --------
$889,870 $879,379
======== ========
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........................................... (11,783) (11,783)
Retained earnings.............................................................. 65,209 54,179
-------- --------
Total common stockholder's equity.......................................... 241,816 230,786
Preferred stock not subject to mandatory redemption............................... 39,105 39,105
Long-term debt and other long-term obligations.................................... 130,397 130,358
-------- --------
411,318 400,249
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock.............................. 52,224 93,474
Accounts payable-
Associated companies........................................................... 43,895 40,172
Other.......................................................................... 1,311 1,294
Notes payable to associated companies............................................. 40,418 11,334
Accrued taxes..................................................................... 35,900 27,091
Accrued interest.................................................................. 2,440 4,396
Other............................................................................. 9,557 8,444
-------- --------
185,745 186,205
-------- --------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes................................................. 93,894 97,871
Accumulated deferred investment tax credits....................................... 3,443 3,516
Asset retirement obligation....................................................... 131,678 129,546
Retirement benefits............................................................... 55,830 54,057
Other............................................................................. 7,962 7,935
-------- --------
292,807 292,925
-------- --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
-------- --------
$889,870 $879,379
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an
integral part of these balance sheets.
92
PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
---------------------------
2004 2003
--------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 19,670 $ 5,864
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization................................ 13,438 13,265
Nuclear fuel and lease amortization........................................ 4,565 3,583
Deferred income taxes, net................................................. (1,231) 6,122
Amortization of investment tax credits..................................... (575) (620)
Cumulative effect of accounting change (Note 2)............................ -- (18,150)
Receivables................................................................ (214) 17,262
Materials and supplies..................................................... (1,075) (431)
Accounts payable........................................................... 3,740 27,844
Accrued taxes.............................................................. 8,809 4,271
Accrued interest........................................................... (1,956) (2,009)
Prepayments and other current assets....................................... (13,334) (16,288)
Asset retirement obligation, net........................................... 3,195 (980)
Other...................................................................... 3,237 600
-------- --------
Net cash provided from operating activities............................ 38,269 40,333
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net................................................. 29,084 --
Redemptions and Repayments-
Long-term debt............................................................. (42,302) (16)
Dividend Payments-
Common stock............................................................... (8,000) (13,000)
Preferred stock............................................................ (640) (912)
-------- --------
Net cash used for financing activities................................. (21,858) (13,928)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (13,998) (31,054)
Contributions to nuclear decommissioning trusts.............................. (399) (399)
Loans from (to) associated companies, net.................................... (116) 4,921
Other........................................................................ (1,898) 732
-------- --------
Net cash used for investing activities................................. (16,411) (25,800)
-------- --------
Net change in cash and cash equivalents......................................... -- 605
Cash and cash equivalents at beginning of period................................ 40 1,222
-------- --------
Cash and cash equivalents at end of period...................................... $ 40 $ 1,827
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an
integral part of these statements.
93
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors of Pennsylvania
Power Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania
Power Company and its subsidiary as of March 31, 2004, and the related
consolidated statements of income and cash flows for each of the three-month
periods ended March 31, 2004 and 2003. 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 balance sheet and the statement of
capitalization as of December 31, 2003, and the related 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 asset retirement
obligations as of January 1, 2003 as discussed in Note 1(E) to those financial
statements) dated February 25, 2004, we expressed an unqualified opinion on
those financial statements. In our opinion, the information set forth in the
accompanying condensed balance sheet as of December 31, 2003, is fairly stated
in all material respects in relation to the balance sheet from which it has been
derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 7, 2004
94
PENNSYLVANIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Penn is a wholly owned, electric utility subsidiary of OE. Penn
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. Penn's wholly owned subsidiary,
Penn Power Funding LLC, began operations on March 30, 2004.
Results of Operations
- ---------------------
Earnings on common stock in the first quarter of 2004 increased to $19
million from $5 million in the first quarter of 2003. Earnings on common stock
in the first quarter of 2003 included an after-tax credit of $11 million from
the cumulative effect of an accounting change due to the adoption of SFAS 143.
Income before the cumulative effect was $20 million in the first three months of
2004, compared to a loss of $5 million for the same period of 2003. Improved
results in the first quarter of 2004 reflect higher operating revenues and lower
operating expenses -- primarily nuclear operating costs.
Operating revenues increased by $14 million or 11.1% in the first
quarter of 2004 compared with the same period in 2003. The higher revenues
primarily resulted from increased wholesale revenues of $11 million due to
increased nuclear generation available for sale to FES in the first quarter of
2004. Retail sales revenues increased $3 million primarily from a 3.1% increase
in generation sales.
Distribution deliveries increased 3.1% in the first quarter of 2004
compared with the corresponding quarter of 2003, with increases in all customer
sectors. The change in revenues from electricity throughput was flat with the
effect of the volume increase offset by lower composite prices.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2004 from the same quarter of 2003 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
---------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. 3.1%
Wholesale............................... 32.1%
---------------------------------------------------
Total Electric Generation Sales........... 18.3%
===================================================
Distribution Deliveries:
Residential............................. 3.1%
Commercial.............................. 0.5%
Industrial.............................. 5.4%
---------------------------------------------------
Total Distribution Deliveries............. 3.1%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $8 million in the
first quarter of 2004 from the first quarter of 2003. The following table
presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes
------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................ $ 2
Purchased power ................................ 4
Nuclear operating costs......................... (28)
Other operating costs........................... (3)
------------------------------------------------------------
Total operation and maintenance expenses..... (25)
Provision for depreciation and amortization..... --
General taxes................................... --
Income taxes.................................... 17
------------------------------------------------------------
Total operating expenses and taxes........... $ (8)
============================================================
Higher fuel costs in the first quarter of 2004, compared with the same
quarter of 2003, resulted from increased nuclear generation. Purchased power
costs were higher in the first three months of 2004 reflecting a 4.8% increase
95
in kilowatt-hour purchases and higher unit costs. Lower nuclear operating costs
occurred in large part due to the absence in 2004 of a refueling outage at
Beaver Valley Unit 1. Beaver Valley Unit 1 (65.00% ownership) experienced a
refueling outage in the first quarter of 2003.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
approximately $2 million in the first quarter of 2004 from the same period last
year, reflecting mandatory and optional redemptions of $83 million total
principal amount of debt securities since the first quarter of 2003.
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 $11 million. The cumulative 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 an $18
million increase to income, or $11 million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
Penn's cash requirements in 2004 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing Penn'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,
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
Penn had $40,000 of cash and cash equivalents as of March 31, 2004 and
December 31, 2003.
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter of
2004, compared with the corresponding period in 2003 were as follows:
Operating Cash Flows 2004 2003
-----------------------------------------------------------------
(In millions)
Cash earnings (1).................. $38 $11
Working capital and other.......... -- 29
-----------------------------------------------------------------
Total.............................. $38 $40
=================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash from operating activities decreased to $38 million in the
first quarter of 2004 from $40 million in the same period of 2003 due to a $27
million increase in cash earnings and a $29 million reduction from working
capital and other changes (primarily change in accounts payable to associated
companies).
Cash Flows From Financing Activities
In the first quarter of 2004, net cash used for financing activities
increased to $22 million from $14 million in the same period last year. The
increase resulted from increased long-term debt redemptions, partially offset by
increased short-term borrowings and reduced common stock dividends to OE.
Penn had approximately $7 million of cash and temporary investments
(which include short-term notes receivable from associated companies) and $40
million of short-term indebtedness as of March 31, 2004. Penn may borrow from
its affiliates on a short-term basis. Penn had the capability to issue $500
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 $521 million of preferred stock (assuming no additional debt was
issued) as of March 31, 2004.
In March 2004, Penn completed an on-balance sheet, receivable
financing transaction which allows it to borrow up to $25 million. The borrowing
rate is based on bank commercial paper rates. Penn is required to pay an annual
facility fee of 0.40% on the entire finance limit. The facility was undrawn as
of March 31, 2004. This facility matures on March 29, 2005.
96
Penn's access to capital markets and costs of financing are dependent
on the ratings of its securities and the securities of OE and FirstEnergy. The
ratings outlook on all of its securities is stable.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net cash used for investing activities totaled $16 million in the
first quarter of 2004, compared to $26 million for the same period of 2003. The
$10 million decrease in funds used for investing activities resulted primarily
from lower capital expenditures partially offset by changes in loans to
associated companies.
During the last three quarters of 2004, capital requirements for
property additions and capital leases are expected to be about $70 million,
including $21 million for nuclear fuel. Penn has additional requirements of
approximately $22 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2004. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
Equity Price Risk
- -----------------
Included in Penn's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $51
million and $50 million as of March 31, 2004 and December 31, 2003,
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, 2004.
Outlook
- -------
Beginning in 1999, Penn's customers were able to select alternative
energy suppliers. Penn continues to deliver power to homes and businesses
through its existing distribution system, which remains regulated. The PPUC
authorized Penn'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.
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, which is referred to as its PLR obligation.
Regulatory Matters
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 late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. Penn is
currently awaiting the PPUC to issue a final order in both matters. The order
97
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports.
On January 16, 2004, the PPUC initiated a formal investigation of
whether Penn's "service reliability performance deteriorated to a point below
the level of service reliability that existed prior to restructuring" in
Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony is
due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this
investigation and the ALJ has been directed to issue a Recommended Decision by
September 30, 2004, in order to allow the PPUC time to issue a Final Order by
year end of 2004. Penn is unable to predict the outcome of the investigation or
the impact of the PPUC order.
Regulatory assets are costs which have been authorized by the PPUC and
the FERC, for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. All of Penn's
regulatory assets are expected to continue to be recovered under the provisions
of its regulatory plan. Penn's regulatory assets totaled $15 million and $28
million as of March 31, 2004 and December 31, 2003, respectively.
Environmental Matters
Various federal, state and local authorities regulate Penn with regard
to air and water quality and other environmental matters. 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 that
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. Overall, Penn believes it is in material
compliance with existing regulations but is unable to predict future change in
regulatory policies and what, if any, the effects of such change would be.
Penn is required to meet federally approved 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 EPA has an interim enforcement policy for SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. Penn cannot predict what action the EPA may take in the future with
respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on Penn's
financial condition and results of operations. Management is unable to predict
the ultimate outcome of this matter and no liability has been accrued as of
March 31, 2004.
Penn is complying with SO2 reduction requirements under the Clean Air
Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity
from lower-emitting plants, and/or using emission allowances. NOx reductions
required by the 1990 Amendments 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
Penn's 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the District
of Columbia based on a conclusion that such NOx emissions are contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets.
Pennsylvania submitted a SIP that required compliance with the NOx budgets at
Penn's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that
requires compliance with the NOx budgets at Penn's Ohio facilities by May 31,
2004. Penn's facilities have complied with the NOx budgets in 2003 and 2004,
respectively.
98
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Reliability Initiatives below). As many of these initiatives
already were in process and budgeted in 2004, FirstEnergy does not believe that
any incremental expenses associated with additional initiatives undertaken
during 2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
99
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
Legal Matters
Various lawsuits, claims and proceedings related to Penn's normal
business operations are pending against Penn, the most significant of which are
described above.
Critical Accounting Policies
Penn prepares its financial statements in accordance with GAAP.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of Penn's assets
are subject to their own specific risks and uncertainties and are regularly
reviewed for impairment. Assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting these specific factors. Penn's more significant accounting policies
are described below.
Regulatory Accounting
Penn is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on 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. 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 electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
electricity sales to individual customers is based on meter readings, which
occur on a systematic basis throughout the month. At the end of each month,
electricity delivered to customers since the last meter reading is estimated and
a corresponding accrual for unbilled revenues is recognized. The determination
of unbilled revenues requires management to make estimates regarding electricity
available for retail load, transmission and distribution line losses,
consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
100
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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 144, Penn periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset might 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 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, Penn recognizes an ARO for the future
decommissioning of its nuclear power plants. The ARO liability represents an
estimate of the fair value of Penn's current obligation related to nuclear
decommissioning and the retirement of other assets. A fair value measurement
inherently involves uncertainty in the amount and timing of settlement of the
liability. Penn used an expected cash flow approach (as discussed in FASB
Concepts Statement No. 7) to measure the fair value of the nuclear
decommissioning ARO. This approach applies probability weighting to discounted
future cash flow scenarios that reflect a range of possible outcomes. The
scenarios consider settlement of the ARO at the expiration of the nuclear power
plants' current license and settlement based on an extended license term.
New Accounting Standards and Interpretations
- --------------------------------------------
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. Penn elected to defer the effects of the Medicare Act due to the lack of
specific guidance. Pursuant to FSP 106-1, Penn began accounting for the effects
of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004
plan amendment that required remeasurement of the plan's obligations. See Note 2
for a discussion of the effect of the federal subsidy and plan amendment on the
consolidated financial statements.
101
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2004 2003
--------- --------
Restated
(See Note 2)
(In thousands)
OPERATING REVENUES.............................................................. $ 498,124 $ 656,952
--------- ---------
OPERATING EXPENSES AND TAXES:
Fuel......................................................................... 1,213 1,334
Purchased power.............................................................. 259,592 362,667
Other operating costs........................................................ 85,603 69,088
--------- ---------
Total operation and maintenance expenses................................. 346,408 433,089
Provision for depreciation and amortization.................................. 94,701 96,973
General taxes................................................................ 15,932 15,812
Income taxes................................................................. 9,113 35,735
--------- ---------
Total operating expenses and taxes....................................... 466,154 581,609
--------- ---------
OPERATING INCOME................................................................ 31,970 75,343
OTHER INCOME.................................................................... 1,503 1,176
--------- ---------
INCOME BEFORE NET INTEREST CHARGES.............................................. 33,473 76,519
--------- ---------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 20,728 23,312
Allowance for borrowed funds used during construction........................ (120) (123)
Deferred interest............................................................ (923) (3,202)
Other interest expense (credit).............................................. 390 (159)
Subsidiary's preferred stock dividend requirements........................... -- 2,674
--------- ---------
Net interest charges..................................................... 20,075 22,502
--------- ---------
NET INCOME...................................................................... 13,398 54,017
PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 125 125
--------- ---------
EARNINGS ON COMMON STOCK........................................................ $ 13,273 $ 53,892
========= =========
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.
102
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
-----------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $3,660,955 $3,642,467
Less-Accumulated provision for depreciation.................................... 1,383,599 1,367,042
---------- ----------
2,277,356 2,275,425
Construction work in progress.................................................. 56,735 48,985
---------- ----------
2,334,091 2,324,410
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 130,623 125,945
Nuclear fuel disposal trust.................................................... 159,710 155,774
Long-term notes receivable from associated companies........................... 20,635 19,579
Other.......................................................................... 18,085 18,744
---------- ----------
329,053 320,042
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 282 271
Receivables-
Customers (less accumulated provisions of $3,924,000 and $4,296,000
respectively, for uncollectible accounts).................................. 182,797 198,061
Associated companies......................................................... 95,370 70,012
Other (less accumulated provisions of $836,000 and $1,183,000
respectively, for uncollectible accounts).................................. 34,879 46,411
Materials and supplies, at average cost........................................ 2,122 2,480
Prepayments and other.......................................................... 24,984 49,360
---------- ----------
340,434 366,595
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 2,456,605 2,558,214
Goodwill....................................................................... 1,998,287 2,001,302
Other.......................................................................... 8,547 8,481
---------- ----------
4,463,439 4,567,997
---------- ----------
$7,467,017 $7,579,044
========== ==========
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........................................................ 3,029,894 3,029,894
Accumulated other comprehensive loss......................................... (51,784) (51,765)
Retained earnings............................................................ 30,406 22,132
---------- ----------
Total common stockholder's equity........................................ 3,162,229 3,153,974
Preferred stock not subject to mandatory redemption............................ 12,649 12,649
Long-term debt................................................................. 1,041,032 1,095,991
---------- ----------
4,215,910 4,262,614
--------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 226,313 175,921
Notes payable -
Associated companies......................................................... 151,241 230,985
Accounts payable-
Associated companies......................................................... 42,066 42,410
Other........................................................................ 90,810 105,815
Accrued taxes................................................................. 50,400 919
Accrued interest............................................................... 25,621 14,843
Other.......................................................................... 60,140 58,094
---------- ----------
646,591 628,987
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 623,875 640,208
Accumulated deferred investment tax credits.................................... 7,315 7,711
Power purchase contract loss liability ........................................ 1,416,257 1,473,070
Nuclear fuel disposal costs.................................................... 168,314 167,936
Asset retirement obligation.................................................... 111,379 109,851
Retirement benefits............................................................ 147,505 159,219
Other.......................................................................... 129,871 129,448
--------- ----------
2,604,516 2,687,443
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ----------
---------- ----------
$7,467,017 $7,579,044
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these balance sheets.
103
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
---------------------------
2004 2003
--------- --------
Restated
(See Note 2)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................................... $ 13,398 $ 54,017
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........................... 94,701 96,973
Other amortization.................................................... 24 185
Deferred costs, net................................................... (49,122) (71,888)
Deferred income taxes, net............................................ 627 14,977
Investment tax credits, net........................................... (397) (575)
Receivables........................................................... 1,438 19,788
Materials and supplies................................................ 358 (226)
Accounts payable...................................................... (15,349) (90,178)
Prepayments and other current assets.................................. 24,376 16,044
Accrued taxes......................................................... 49,480 45,157
Accrued interest...................................................... 10,778 5,771
Accrued retirement benefit obligation................................. (11,714) --
Other................................................................. 3,444 6,034
--------- ---------
Net cash provided from operating activities......................... 122,042 96,079
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments -
Long-term debt.......................................................... (3,591) (10,090)
Short-term borrowings, net.............................................. (79,744) --
Dividend Payments-
Common stock............................................................ (5,000) (89,000)
Preferred stock......................................................... (125) (125)
--------- ---------
Net cash used for financing activities.............................. (88,460) (99,215)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................ (28,212) (24,551)
Loans from (to) associated companies, net................................. (1,056) 24,750
Other..................................................................... (4,303) (50)
--------- ---------
Net cash provided from (used for) investing activities.............. (33,571) 149
--------- ---------
Net increase (decrease) in cash and cash equivalents......................... 11 (2,987)
Cash and cash equivalents at beginning of period ............................ 271 4,823
--------- ---------
Cash and cash equivalents at end of period................................... $ 282 $ 1,836
========= =========
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.
104
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, 2004, and the related
consolidated statements of income and cash flows for each of the three-month
periods ended March 31, 2004 and 2003. 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 2 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the three-month period ended March 31, 2003.
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, 2003, 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 (which contained references to the Company's change
in its method of accounting for asset retirement obligations as of January 1,
2003 as discussed in Note 1(E) to those consolidated financial statements) dated
February 25, 2004, we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004
105
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy.
JCP&L 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 PLR obligation
known as BGS for customers who elect to retain JCP&L as their power supplier.
Restatements of Previously Reported Quarterly Results
- -----------------------------------------------------
As discussed in Note 2 to Consolidated Financial Statements, JCP&L's
quarterly results for the first quarter of 2003 have been restated to correct
the amounts reported for operating expenses. JCP&L's costs which were originally
recorded as operating expenses and should have been capitalized to construction
were $0.2 million ($0.1 million after-tax) in the first quarter of 2003. The
impact of these adjustments was not material to JCP&L's Consolidated Balance
Sheets or Consolidated Statements of Cash Flows for any quarter of 2003.
Results of Operation
- --------------------
Earnings on common stock in the first quarter of 2004 decreased to $13
million from $54 million in the first quarter of 2003. Lower operating revenues
primarily due to decreases in wholesale sales and lower rates resulting from a
NJBPU rate order and higher operating costs were partially offset by lower
purchased power costs.
Operating revenues decreased by $159 million or 24.2% in the first
quarter of 2004 compared with the same period in 2003. The lower revenues
resulted from lower wholesale revenues that decreased by $78 million over the
first quarter of 2003. JCP&L entered into long-term power purchase agreements
with the divestiture of its generating facilities. JCP&L was able to sell any
power in excess of its retail customer needs to the wholesale market. The
long-term power purchase agreements ended during 2003 and as a result, sales to
the wholesale market also ceased.
While distribution deliveries increased 1.3% in the first quarter of
2004 from the corresponding quarter of 2003, revenues from electricity
throughput declined by $76 million. On July 25, 2003, the NJBPU announced its
JCP&L base electric rate proceeding decision (see Regulatory Matters), which
reduced JCP&L's distribution rates effective August 1, 2003. The lower rates
reduced revenues by $33 million in the first quarter of 2004. A higher level of
shopping contributed to the remainder of the decline in operating revenues. The
industrial customer sector deliveries increased 6.1% primarily due to JCP&L's
largest industrial customer increasing its consumption by 18%. Changes in
distribution deliveries in the first quarter of 2004 compared with the first
quarter of 2003 are summarized in the following table:
Changes in Kilowatt-Hour Deliveries
----------------------------------------------------------
Increase (Decrease)
Residential........................... 1.2%
Commercial............................ (0.1)%
Industrial............................ 6.1%
----------------------------------------------------------
Total Distribution Deliveries.................... 1.3%
==========================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased $115 million in the first
quarter of 2004 compared with the first quarter of 2003, primarily due to
reduced purchased power costs offset in part by increased other operating
expenses. The following table presents changes from the prior year by expense
category.
106
Operating Expenses and Taxes - Changes
-----------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ --
Purchased power.................................. (103)
Other operating costs............................ 17
------------------------------------------------------------
Total operation and maintenance expenses....... (86)
Provision for depreciation and amortization...... (2)
General taxes.................................... --
Income taxes..................................... (27)
-------------------------------------------------------------
Total operating expenses and taxes............. $(115)
=============================================================
Lower purchased power costs in the first quarter of 2004, compared to
the same quarter of 2003, were due primarily to decreased kilowatt-hour
purchases through two-party agreements. The increase in other operating costs
was attributed to JCP&L's accelerated reliability program (see Regulatory
Matters).
Net Interest Charges
Net interest charges decreased by $2 million in the first quarter of
2004 compared with the first quarter of 2003, primarily due to debt redemptions
since the end of the first quarter of 2003.
Capital Resources and Liquidity
- -------------------------------
JCP&L's cash requirements in 2004 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 two 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
JCP&L had $0.3 million of cash and cash equivalents as of March 31,
2004 and December 31, 2003.
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter of
2004, compared to the first quarter of 2003 were as follows:
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 59 $94
Working capital and other............ 63 2
-------------------------------------------------------------
Total................................ $122 $96
=============================================================
(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 increased to $122 million in the
first quarter of 2004 from $96 million in the first quarter of 2003. The
increase was due to a $61 million increase in funds provided from working
capital and other changes, partially offset by a $35 million decrease in cash
earnings. The increase in working capital reflects a $75 million decrease in
cash requirements for accounts payable in 2004 as compared to 2003. The cash
earnings decrease was mostly attributable to lower revenues.
Cash Flows From Financing Activities
In the first quarter of 2004, net cash used for financing activities
of $88 million primarily reflected the redemption of $80 million of short-term
borrowings, $3 million of long-term debt and $5 million of common stock dividend
payments to FirstEnergy. In the first quarter of 2003, net cash used for
financing activities totaled $99 million, primarily due to the redemption of
debt and $89 million in common stock dividend payments to FirstEnergy.
JCP&L may borrow from its affiliates on a short-term basis. JCP&L will
not issue first mortgage bonds other than as collateral for senior notes, since
its senior note indenture prohibits (subject to certain exceptions) it from
107
issuing any debt which is senior to the senior notes. Based upon applicable
earnings coverage tests, JCP&L could not issue any first mortgage bonds or
preferred stock as of March 31, 2004.
On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes
due 2016. The proceeds of this transaction will be used to redeem $40 million of
7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs
due 2005. The remaining proceeds will be used to fund the mandatory redemption
of JCP&L's $160 million of 7.125% FMB due October 1, 2004 and to reduce
short-term debt.
JCP&L has the ability to borrow from its regulated affiliates and
FirstEnergy to meet its short-term working capital requirements. FESC
administers this money pool and tracks surplus funds of FirstEnergy and its
regulated subsidiaries, as well as proceeds available from bank borrowings.
Companies receiving a loan under the money pool agreements must repay the
principal amount of such a loan, together with accrued interest, within 364 days
of borrowing the funds. The rate of interest is the same for each company
receiving a loan from the pool and is based on the average cost of funds
available through the pool. The average interest rate for borrowings in the
first quarter of 2004 was 1.30%.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net cash used for investing activities totaled $34 million in the
first quarter of 2004, compared with net cash provided from investing activities
of $0.1 million in the first quarter of 2003. The $34 million increase was
primarily due to the $1 million in loan payments made to associated companies in
2004 as compared to the $25 million in loan payments received from associated
companies in 2003, as well as $4 million in increased property additions in
2004.
During the last three quarters of 2004, capital requirements for
property additions are expected to be about $122 million. JCP&L has additional
requirements of approximately $160 million for maturing long-term debt during
the remainder of 2004. These cash requirements (excluding debt refinancings) are
expected to be satisfied from internal cash and short-term credit arrangements.
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 2004 is summarized in the
following table:
108
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, 2004................... $ 16 $ -- $ 16
New contract value when entered............................... -- -- --
Additions/change in value of existing contracts............... (1) -- (1)
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. -- -- --
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (1)... $ 15 $ -- $ 15
=================================================================================================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $ -- $ --
Regulatory Liability.......................................... $ (1) $ -- $ (1)
(1) Includes $15 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.
Derivatives included on the Consolidated Balance Sheet as of March 31, 2004:
Non-Hedge Hedge Total
---------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $-- $ -- $--
Non-Current-
Other Deferred Charges............ 15 -- 15
-------------------------------------------------------------------
Net assets........................ $15 $ -- $15
===================================================================
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 2004 2005 2006 2007 Thereafter Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(1) $ 2 $ 3 $ -- $ -- $ -- $ 5
Prices based on models -- -- 2 2 6 10
- --------------------------------------------------------------------------------------------------------------
Total(2) $ 2 $ 3 $ 2 $ 2 $ 6 $15
===============================================================================================================
(1) Broker quote sheets.
(2) Includes $15 million from an embedded option that is offset by a regulatory
liability and does not affect earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the
market risk of its commodity 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, 2004.
Equity Price Risk
Included in JCP&L's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $72
million and $69 million as of March 31, 2004 and December 31, 2003,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $7 million reduction in fair value as of March 31, 2004.
109
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 FERC 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
$2.5 billion and $2.6 billion as of March 31, 2004 and December 31, 2003,
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's two August 2002 rate
filings requested increases in base electric rates of approximately $98 million
annually and requested the recovery of deferred energy 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. In
July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision
which reduced JCP&L's annual revenues by approximately $62 million effective
August 1, 2003. The NJBPU decision also provided for an interim return on equity
of 9.5% on JCP&L's rate base for the next six to twelve months. During that
period, JCP&L will initiate another proceeding to request recovery of additional
costs incurred to enhance system reliability. In that proceeding, the NJBPU
could increase the return on equity to 9.75% or decrease it to 9.25%, depending
on its assessment of the reliability of JCP&L's service. Any reduction would be
retroactive to August 1, 2003. The revenue decrease in the decision consists of
a $223 million decrease in the electricity delivery charge, a $111 million
increase due to the August 1, 2003 expiration of annual customer credits
previously mandated by the New Jersey transition legislation, a $49 million
increase in the MTC tariff component, and a net $1 million increase in the SBC
charge. The MTC allowed for the recovery of $465 million in deferred energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary settlement agreement between
certain parties. As a result, JCP&L recorded charges to net income for the year
ended December 31, 2003, aggregating $185 million ($109 million net of tax)
consisting of the $153 million deferred energy costs and other regulatory
assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on
August 15, 2003 with respect to the following issues: (1) the disallowance of
the $153 million deferred energy costs; (2) the reduced rate of return on
equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On
October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU
decision and order is issued. This is expected to occur in the second quarter of
2004.
On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
JCP&L implement a series of actions to improve reliability in the area affected
by the outages. The NJBPU adopted the findings and recommendations of the
Interim Report on December 17, 2003, and ordered JCP&L to implement the
recommended actions on a staggered basis, with initial actions to be completed
by March 31, 2004. JCP&L expects to spend $12.5 million implementing these
actions during 2004. In late 2003, in accordance with a Stipulation concerning
an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an
audit of the planning, operations and maintenance practices, policies and
procedures of JCP&L. The audit was expanded to include the July 2003 outage and
was completed in January 2004. JCP&L is awaiting the issuance of the final audit
report and is unable to predict the outcome of the audit; no liability has been
accrued as of March 31, 2004.
On April 28, 2004, the NJBPU directed JCP&L to file testimony by the
end of May 2004, either supporting a continuation of the current level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers,
or, alternatively, proposing a reduction, termination or capping of the funding.
JCP&L cannot predict the outcome of this matter.
Environmental Matters
JCP&L has been named as a 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, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheets, 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 by JCP&L through a non-bypassable SBC. JCP&L has
accrued liabilities aggregating approximately $45.6 million as of March 31,
2004. JCP&L accrues environmental liabilities only when it can conclude that it
is probable that an obligation for such costs exists and can reasonably
determine the amount of such costs. Unasserted claims are reflected in JCP&L's
determination of environmental liabilities and are accrued in the period that
they are both probable and reasonably estimable.
110
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Reliability Initiatives below). As many of these initiatives
already were in process and budgeted in 2004, FirstEnergy does not believe that
any incremental expenses associated with additional initiatives undertaken
during 2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
111
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against us, the most significant of which are
described herein.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L's territory. In an investigation into the
causes of the outages and the reliability of the transmission and distribution
systems of all four New Jersey electric utilities, the NJBPU concluded that
there was not a prima facie case demonstrating that, overall, JCP&L provided
unsafe, inadequate or improper service to its customers. Two class action
lawsuits (subsequently consolidated into a single proceeding) were filed in New
Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies,
seeking compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
Since July 1999, this litigation has involved a substantial amount of
legal discovery including interrogatories, request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L employees. In addition, there have been many motions filed and
argued by the parties involving issues such as the primary jurisdiction and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate Division determined that the trial court has proper jurisdiction
over this litigation. In August 2002, the trial court granted partial summary
judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, and strict products liability. In
November 2003, the trial court granted JCP&L's motion to decertify the class and
denied plaintiffs' motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings have been appealed to the Appellation Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of March 31, 2004.
Critical Accounting Policies
JCP&L prepares its consolidated financial statements in accordance
with GAAP. 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 these specific factors. JCP&L's more significant
accounting policies are described below.
Regulatory Accounting
JCP&L is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on costs that the regulatory agencies
determine JCP&L is permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated company. This rate-making process results in the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in New Jersey, a significant amount of regulatory
assets have been recorded - $2.5 billion as of March 31, 2004. JCP&L regularly
reviews these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. JCP&L continually monitors its derivative contracts to determine if
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, JCP&L enters into commodity contracts,
as well as interest rate swaps, which increase the impact of derivative
accounting judgments.
112
Revenue Recognition
JCP&L follows the accrual method of accounting for revenues,
recognizing revenue for electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
electricity sales to individual customers is based on meter readings, which
occur on a systematic basis throughout the month. At the end of each month,
electricity delivered to customers since the last meter reading is estimated and
a corresponding accrual for unbilled revenues is recognized. The determination
of unbilled revenues requires management to make estimates regarding electricity
available for retail load, transmission and distribution line losses,
consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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 144, JCP&L periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset might 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 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).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
113
Nuclear Decommissioning
In accordance with SFAS 143, JCP&L recognizes an ARO for the future
decommissioning of TMI-2. The ARO liability represents an estimate of the fair
value of JCP&L's current obligation related to nuclear decommissioning. A fair
value measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. JCP&L used an expected cash flow approach (as
discussed in FASB Concepts Statement No. 7) to measure the fair value of the
nuclear decommissioning ARO. This approach applies probability weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.
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, JCP&L
evaluates 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), the goodwill is tested for
impairment. If impairment were to be indicated, JCP&L would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill. JCP&L's annual review was completed in the
third quarter of 2003, with no impairment indicated. 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. In the first
quarter of 2004, JCP&L reduced goodwill by $3 million for interest received on a
pre-merger income tax refund. As of March 31, 2004, JCP&L had $2 billion of
goodwill.
New Accounting Standards and Interpretations
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, JCP&L adopted FIN 46R for interests in VIEs commonly referred
to as special-purpose entities effective December 31, 2003 and for all other
types of entities effective March 31, 2004. Adoption of FIN 46R did not have a
material impact on JCP&L's financial statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.
For the quarter ended March 31, 2004, JCP&L evaluated, among other
entities, its power purchase agreements and determined that it is possible that
six NUG entities might be considered variable interest entities. JCP&L has
requested but not received the information necessary to determine whether these
entities are VIEs or whether JCP&L is the primary beneficiary. In most cases,
the requested information was deemed to be competitive and proprietary data. As
such, JCP&L applied the scope exception that exempts enterprises unable to
obtain the necessary information to evaluate entities under FIN 46R. The maximum
exposure to loss from these entities results from increases in the variable
pricing component under the contract terms and cannot be determined without the
requested data. JCP&L's purchased power costs from these entities during the
first quarters of 2004 and 2003 were $28 million and $34 million, respectively.
JCP&L is required to continue to make exhaustive efforts to obtain the necessary
information in future periods and is unable to determine the possible impact of
consolidating any such entity without this information.
114
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------
2004 2003
--------- --------
(In thousands)
OPERATING REVENUES.............................................................. $ 260,898 $ 251,203
--------- ---------
OPERATING EXPENSES AND TAXES:
Purchased power.............................................................. 143,456 135,291
Other operating costs........................................................ 33,048 33,735
--------- ---------
Total operation and maintenance expenses................................. 176,504 169,026
Provision for depreciation and amortization.................................. 35,395 34,108
General taxes................................................................ 17,736 16,860
Income taxes................................................................. 7,980 7,198
--------- ---------
Total operating expenses and taxes....................................... 237,615 227,192
--------- ---------
OPERATING INCOME................................................................ 23,283 24,011
OTHER INCOME.................................................................... 5,526 5,168
--------- ---------
INCOME BEFORE NET INTEREST CHARGES.............................................. 28,809 29,179
--------- ---------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 10,147 10,539
Allowance for borrowed funds used during construction........................ (71) (73)
Deferred interest............................................................ -- (440)
Other interest expense....................................................... 689 463
Subsidiary's preferred stock dividend requirements........................... -- 1,890
--------- ---------
Net interest charges..................................................... 10,765 12,379
--------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 18,044 16,800
Cumulative effect of accounting change (net of income taxes of $154,000) (Note 2) -- 217
--------- ---------
NET INCOME...................................................................... $ 18,044 $ 17,017
========= =========
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.
115
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
-------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $1,847,899 $1,838,567
Less-Accumulated provision for depreciation.................................... 780,873 772,123
---------- ----------
1,067,026 1,066,444
Construction work in progress.................................................. 20,599 21,980
---------- ----------
1,087,625 1,088,424
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 200,502 192,409
Long-term notes receivable from associated companies........................... 10,636 9,892
Other.......................................................................... 33,814 34,922
---------- ----------
244,952 237,223
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 120 121
Receivables-
Customers (less accumulated provisions of $4,886,000 and $4,943,000
respectively, for uncollectible accounts)................................. 114,964 118,933
Associated companies......................................................... 48,939 45,934
Notes receivable from associated companies................................... 126,525 10,467
Other (less accumulated provisions of $21,000 and $68,000 respectively,
for uncollectible accounts)................................................ 17,947 22,750
Prepayments and other.......................................................... 43,201 6,600
---------- ----------
351,696 204,805
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 989,863 1,028,432
Goodwill....................................................................... 880,468 884,279
Other.......................................................................... 32,381 30,824
---------- ----------
1,902,712 1,943,535
---------- ----------
$3,586,985 $3,473,987
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding................................................. $1,298,130 $1,298,130
Accumulated other comprehensive loss......................................... (35,721) (32,474)
Retained earnings............................................................ 40,055 27,011
---------- ----------
Total common stockholder's equity.......................................... 1,302,464 1,292,667
Long-term debt and other long-term obligations................................. 738,283 636,301
---------- ----------
2,040,747 1,928,968
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 136,232 40,469
Short-term borrowings -
Associated companies......................................................... - 65,335
Accounts payable-
Associated companies......................................................... 64,378 45,459
Other........................................................................ 21,807 33,878
Accrued taxes................................................................. 7,216 8,762
Accrued interest............................................................... 7,383 11,848
Other.......................................................................... 23,242 22,162
---------- ----------
260,258 227,913
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 295,962 297,140
Accumulated deferred investment tax credits.................................... 11,491 11,696
Power purchase contract loss liability......................................... 551,598 584,340
Nuclear fuel disposal costs.................................................... 38,021 37,936
Asset retirement obligation.................................................... 213,261 210,178
Pensions and other postretirement benefits..................................... 106,625 105,552
Other.......................................................................... 69,022 70,264
---------- ----------
1,285,980 1,317,106
--------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
---------- ----------
$3,586,985 $3,473,987
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these balance sheets.
116
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
---------------------------
2004 2003
--------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................................... $ 18,044 $ 17,017
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........................... 35,395 34,108
Deferred costs, net................................................... (16,792) (10,767)
Deferred income taxes, net............................................ 2,639 1,385
Amortization of investment tax credits................................ (206) (205)
Accrued retirement benefit obligation................................. 1,074 --
Accrued compensation, net............................................. (634) (104)
Cumulative effect of accounting change (Note 2)....................... -- (371)
Receivables........................................................... 5,767 18,344
Materials and supplies................................................ 18 (139)
Accounts payable...................................................... 6,848 31,968
Accrued taxes......................................................... (1,546) (11,916)
Accrued interest...................................................... (4,465) (4,798)
Prepayments and other current assets.................................. (36,618) (30,140)
Other................................................................. (8,265) (11,613)
--------- --------
Net cash provided from operating activities......................... 1,259 32,769
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt.......................................................... 247,607 247,696
Redemptions and Repayments-
Long-term debt.......................................................... (50,435) (40,000)
Short-term borrowings, net.............................................. (65,335) (23,087)
Dividend Payments-
Common Stock............................................................ (5,000) --
---------- --------
Net cash provided from financing activities........................... 126,837 184,609
--------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................ (8,962) (10,333)
Contributions to nuclear decommissioning trusts........................... (2,371) (2,371)
Loans to associated companies, net........................................ (116,802) (8,005)
Other..................................................................... 38 217
--------- --------
Net cash used for investing activities.............................. (128,097) (20,492)
--------- --------
Net increase (decrease) in cash and cash equivalents......................... (1) 196,886
Cash and cash equivalents at beginning of period ............................ 121 15,685
--------- --------
--------- --------
Cash and cash equivalents at end of period................................... $ 120 $212,571
========= ========
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.
117
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, 2004, and the related
consolidated statements of income and cash flows for each of the three-month
periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change
in its method of accounting for asset retirement obligations as of January 1,
2003 as discussed in Note 1(E) to those consolidated financial statements and
the Company's change in its method of accounting for the consolidation of
variable interest entities as of December 31, 2003 as discussed in Note 8 to
those consolidated financial statements) dated February 25, 2004, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2003, 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 7, 2004
118
METROPOLITAN EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy.
Met-Ed provides regulated transmission and distribution services in eastern
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 PLR
obligations to customers who elect to retain Met-Ed as their power supplier.
Results of Operations
- ---------------------
Net income in the first quarter of 2004 increased to $18 million from
$17 million in the first quarter of 2003. Results improved in the first quarter
of 2004 due to increased retail electric sales revenues and lower interest
charges, partially offset by higher purchased power costs.
Operating revenues increased by $10 million, or 3.9% in the first
quarter of 2004 compared with the first quarter of 2003. The higher revenues
primarily resulted from increased distribution revenues of $10 million from
electricity throughput as a result of higher unit prices and increased
consumption by the commercial and industrial sectors -- reflecting the effects
of an improving regional economy.
Higher retail generation kilowatt-hour sales of 7.9% increased
operating revenues by $2 million. The increase was primarily due to more
commercial and industrial customers returning to Met-Ed as their electric
service provider. Sales of electric generation by alternative suppliers as a
percent of total sales delivered in Met-Ed's franchise area decreased to 10.3%
in the first quarter of 2004 from 15.8% in the same period of 2003. Wholesale
revenues decreased by $1 million, reflecting lower sales to affiliated companies
and to the wholesale market.
Changes in distribution deliveries in the first quarter of 2004
compared to the first quarter 2003 are summarized in the following table:
Changes in Kilowatt-Hour Sales
---------------------------------------------------
Increase (Decrease)
Distribution Deliveries:
Residential............................. (0.6)%
Commercial.............................. 3.9%
Industrial.............................. 1.5%
---------------------------------------------------
Total Distribution Deliveries............. 1.3%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased $10 million in the first
quarter of 2004 from the first quarter of 2003. Purchased power costs were $8
million higher due to increased PLR kilowatt-hour purchases from FES (due to
increased generation sales requirements), partially offset by reduced
above-market NUG costs. Other operating costs were lower in 2004 in part due to
lower employee benefit costs. Depreciation and amortization expenses were higher
due to increased amortization of regulatory assets related to CTC revenue
recovery. General taxes increased due to gross receipts taxes and higher payroll
taxes related to the transfer of employees to Met-Ed from GPUS.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $2
million in the first quarter of 2004 from the same quarter of last year,
reflecting redemptions and refinancings since the end of 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 $217,000. The cumulative
adjustment for unrecognized depreciation and accretion offset by the reduction
in the existing decommissioning liabilities was a $371,000 increase to income,
or $217,000 net of income taxes.
119
Capital Resources and Liquidity
- -------------------------------
Met-Ed expects to meet its cash requirements in 2004 for operating
expenses, construction expenditures, scheduled debt maturities and optional debt
redemptions 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, 2004, Met-Ed had $120,000 of cash and cash equivalents
compared with $121,000 as of December 31, 2003. The major sources for changes in
these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities in the first quarter of 2004
and 2003 were as follows:
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 39 $ 41
Working capital and other............ (38) (8)
-------------------------------------------------------------
Total................................ $ 1 $ 33
=============================================================
(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 provided from operating activities decreased $32 million in
the first quarter of 2004 from the first quarter of 2003 as a result of a $30
million decrease from working capital and other changes and a $2 million
decrease in cash earnings. The largest factor contributing to the change in
working capital was a $25 million decrease in accounts payable.
Cash Flows From Financing Activities
In the first quarter of 2004, net cash provided from financing
activities of $127 million reflected the issuance of $250 million of senior
notes, partially offset by the redemption of $50 million of long-term debt and
$65 million of short-term debt, and a common stock dividend of $5 million to
FirstEnergy. Net cash provided from financing activities totaled $185 million in
the first quarter of 2003, due to 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.
As of March 31, 2004, Met-Ed had approximately $127 million of cash
and temporary investments (which include short-term notes receivable from
associated companies) and no outstanding short-term borrowings. Met-Ed will not
issue first mortgage bonds since its senior note indentures prohibit (subject to
certain exceptions) it from issuing any debt which is senior to the senior
notes. Because Met-Ed satisfied the provisions of its senior note indenture for
the release of all FMBs held as collateral for senior notes in March 2004, it is
no longer required to issue FMBs as collateral for future issuances of senior
notes and therefore not limited as to the amount of senior notes it may issue.
Met-Ed had no restrictions on the issuance of preferred stock.
Met-Ed has the ability to borrow from its regulated affiliates and
FirstEnergy to meet its short-term working capital requirements. FESC
administers this money pool and tracks surplus funds of FirstEnergy and its
regulated subsidiaries, as well as proceeds available from bank borrowings.
Available bank borrowings include $1.75 billion from FirstEnergy's and OE's
revolving credit facilities. Companies receiving a loan under the money pool
agreements must repay the principal amount of such a loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from the pool and is based on the average
cost of funds available through the pool. The average interest rate for
borrowings in the first quarter of 2004 was 1.30%.
In March 2004, Met-Ed completed an on-balance sheet, receivable
financing transaction which allows it to borrow up to $80 million. The borrowing
rate is based on bank commercial paper rates. Met-Ed is required to pay an
annual facility fee of 0.30% on the entire finance limit. The facility was
undrawn as of March 31, 2004. This facility matures on March 29, 2005.
Met-Ed's access to capital markets and costs of financing are
dependent on the ratings of its securities and that of FirstEnergy. The ratings
outlook on all of its securities is stable.
120
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
In the first quarter of 2004, net cash used in investing activities
totaled $128 million, compared to $20 million in the first quarter of 2003. The
change resulted from a $108 million increase in loan payments to associated
companies offset in part by slightly lower property additions. Expenditures for
property additions primarily support Met-Ed's energy delivery operations.
During the remaining quarters of 2004, capital requirements for
property additions are expected to be about $46 million. Met-Ed has additional
requirements of approximately $136 million for maturing long-term debt during
the remainder of 2004. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements.
Off-Balance Sheet Arrangements
- ------------------------------
As of March 31, 2004, off-balance sheet arrangements include certain
statutory business trusts created by Met-Ed to issue trust preferred securities
aggregating $93 million. These trusts were included in the consolidated
financial statements of Met-Ed prior to the adoption of FIN 46R, but have
subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest
Entities). Deconsolidation has not resulted in any change in outstanding debt.
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 2004 is summarized in the following table:
121
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, 2004................... $ 31 $ -- $ 31
New contract value when entered............................... -- -- --
Additions/change in value of existing contracts............... (1) -- (1)
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. -- -- --
- -------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (1)... $ 30 $ -- $ 30
=================================================================================================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $ -- $ --
Regulatory Liability.......................................... $ (1) $ -- $ (1)
(1) Includes $30 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.
Derivatives included on the Consolidated Balance Sheet as of March 31, 2004:
Non-Hedge Hedge Total
-------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $-- $ -- $--
Non-Current-
Other Deferred Charges............ 30 -- 30
-------------------------------------------------------------------
Net assets........................ $30 $ -- $30
===================================================================
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:
Source of Information
- - Fair Value by Contract Year 2004 2005 2006 2007 Thereafter Total
- ---------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(1) $ 3 $ 5 $ -- $ -- $-- $ 8
Prices based on models -- -- 5 5 12 22
- ---------------------------------------------------------------------------------------------------------
Total(2) $ 3 $ 5 $ 5 $ 5 $12 $30
=========================================================================================================
(1) Broker quote sheets.
(2) Includes $30 million from an embedded option that is offset by a regulatory
liability and does not affect earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the
market risk of its commodity 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, 2004.
Equity Price Risk
Included in Met-Ed's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $119
million and $114 million as of March 31, 2004 and December 31, 2003,
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, 2004.
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 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
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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 FERC 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 its regulatory plan. Met-Ed's regulatory assets totaled $990 million and
$1.03 billion as of March 31, 2004 and December 31, 2003, respectively.
Regulatory Matters
In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate proceedings which approved the
FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy
costs, permitting Met-Ed to defer, for future recovery, energy costs in excess
of amounts reflected in its capped generation rates retroactive to January 1,
2001. This PLR deferral accounting procedure was later reversed in a February
2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed
the PPUC decision regarding approval of the merger, remanding the decision to
the PPUC only with respect to the issue of merger savings. Met-Ed established a
$103.0 million reserve in 2002 for its PLR deferred energy costs incurred prior
to its acquisition by FirstEnergy, reflecting the potential adverse impact of
the then pending Pennsylvania Supreme Court decision whether to review the
Commonwealth Court decision. The reserve increased goodwill by an aggregate net
of tax amount of $60.3 million.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the ALJ for hearings, directed Met-Ed to file a position paper on the
effect of the Commonwealth Court order on the Settlement Stipulation and allowed
other parties to file responses to the position paper. Met-Ed filed a letter
with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and
reinstating Met-Ed's restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed to file tariffs within thirty days of the order to reflect
the CTC rates and shopping credits that were in effect prior to the June 21,
2001 order to be effective upon one day's notice. In response to that order,
Met-Ed filed these supplements to its tariffs to become effective October 24,
2003.
On October 8, 2003, Met-Ed filed a petition for clarification relating
to the October 2, 2003 order on two issues: to establish June 30, 2004 as the
date to fully refund the NUG trust fund and to clarify that the ordered
accounting treatment regarding the CTC rate/shopping credit swap should follow
the ratemaking, and that the PPUC's findings would not impair its rights to
recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in
the proceedings) petitioned the PPUC to direct Met-Ed to reinstate accounting
for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several
other parties also filed petitions. On October 16, 2003, the PPUC issued a
reconsideration order granting the date requested by Met-Ed for the NUG trust
fund refund and, denying Met-Ed's other clarification requests and granting
ARIPPA's petition with respect to the retroactive accounting treatment of the
changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed filed
an Objection with the Commonwealth Court asking that the Court reverse the
PPUC's finding that requires Met-Ed to treat the stipulated CTC rates that were
in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying Met-Ed's objection without explanation. Due to the vagueness of the
Order, Met-Ed, on October 31, 2003, filed an Application for Clarification with
the judge. Concurrent with this filing, Met-Ed, in order to preserve its rights,
also filed with the Commonwealth Court both a Petition for Review of the PPUC's
October 16 and October 22 Orders, and an application for reargument, if the
judge, in his clarification order, indicates that Met-Ed's objection was
intended to be denied on the merits. In addition to these findings, Met-Ed, in
compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the
twelve months ended December 31, 2001 and 2002, and for the first two quarters
of 2003, reflecting balances consistent with the PPUC's findings in their
Orders.
Effective September 1, 2002, Met-Ed agreed to purchase a portion of
its PLR requirements from FES through a wholesale power sale agreement. The PLR
sale 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 under its NUG contracts and other power contracts with
nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure
to high wholesale power prices by providing power at a fixed price for its
uncommitted PLR energy costs during the term of the agreement with FES. FES has
hedged most of Met-Ed'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 is authorized to continue deferring
differences between NUG contract costs and current market prices.
123
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed is
currently awaiting the PPUC to issue a final order in both matters. The order
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports.
On January 16, 2004, the PPUC initiated a formal investigation of
whether Met-Ed's "service reliability performance deteriorated to a point below
the level of service reliability that existed prior to restructuring" in
Pennsylvania. Discovery has commenced in the proceeding and Met-Ed's testimony
is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this
investigation and the ALJ has been directed to issue a Recommended Decision by
September 30, 2004, in order to allow the PPUC time to issue a Final Order by
year end of 2004. Met-Ed is unable to predict the outcome of the investigation
or the impact of the PPUC order.
Environmental Matters
Met-Ed has been named as a 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, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheets, 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 $50,000 as of March 31, 2004. Met-Ed accrues
environmental liabilities only when it can conclude that it is probable that an
obligation for such costs exists and can reasonably determine the amount of such
costs. Unasserted claims are reflected in Met-Ed's determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Reliability Initiatives below). As many of these initiatives
already were in process and budgeted in 2004, FirstEnergy does not believe that
any incremental expenses associated with additional initiatives undertaken
during 2004 will have a material effect on its operations or financial results.
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
124
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
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.
Critical Accounting Policies
Met-Ed prepares its consolidated financial statements in accordance
with GAAP. Application of these principles often requires a high degree of
judgment, estimates and assumptions that affect financial results. All of
Met-Ed's assets are subject to their own specific risks and uncertainties and
are regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting these specific factors. Met-Ed's more significant
accounting policies are described below.
Regulatory Accounting
Met-Ed is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on costs that the regulatory agencies
determine Met-Ed is permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated company. This rate-making process results in the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in Pennsylvania, a significant amount of
regulatory assets have been recorded - $990 million as of March 31, 2004. Met-Ed
regularly reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future.
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
125
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. Met-Ed continually monitors its derivative contracts to determine if
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, Met-Ed enters into commodity contracts,
as well as interest rate swaps, which increase the impact of derivative
accounting judgments.
Revenue Recognition
Met-Ed follows the accrual method of accounting for revenues,
recognizing revenue for electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
electricity sales to individual customers is based on meter readings, which
occur on a systematic basis throughout the month. At the end of each month,
electricity delivered to customers since the last meter reading is estimated and
a corresponding accrual for unbilled revenues is recognized. The determination
of unbilled revenues requires management to make estimates regarding electricity
available for retail load, transmission and distribution line losses,
consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% 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 144, Met-Ed periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset might 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 has
126
occurred, Met-Ed recognizes a loss - calculated as the difference between the
carrying value and the estimated fair value of the asset (discounted future net
cash flows).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, Met-Ed recognizes an ARO for the future
decommissioning of TMI-2. The ARO liability represents an estimate of the fair
value of Met-Ed's current obligation related to nuclear decommissioning. A fair
value measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. Met-Ed used an expected cash flow approach (as
discussed in FASB Concepts Statement No. 7) to measure the fair value of the
nuclear decommissioning ARO. This approach applies probability weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.
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, Met-Ed
evaluates 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), the goodwill is tested for
impairment. If impairment were to be indicated, Met-Ed would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill. Met-Ed's annual review was completed in the
third quarter of 2003, with no impairment indicated. 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 Met-Ed's future evaluations of goodwill. In the first
quarter of 2004, Met-Ed reduced goodwill by $4 million for interest received on
a pre-merger income tax refund. As of March 31, 2004, Met-Ed had $880 million of
goodwill.
New Accounting Standards and Interpretations
- --------------------------------------------
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, Met-Ed adopted FIN 46R for interests in VIEs commonly referred
to as special-purpose entities effective December 31, 2003 and for all other
types of entities effective March 31, 2004. Adoption of FIN 46R did not have a
material impact on Met-Ed's financial statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.
For the quarter ended March 31, 2004, Met-Ed evaluated, among other
entities, its power purchase agreements and determined that it is possible that
one NUG entity might be considered a variable interest entity. Met-Ed has
requested but not received the information necessary to determine whether this
entity is a VIE or whether Met-Ed is the primary beneficiary. In most cases, the
requested information was deemed to be competitive and proprietary data. As
such, Met-Ed applied the scope exception that exempts enterprises unable to
obtain the necessary information to evaluate entities under FIN 46R. The maximum
exposure to loss from these entities results from increases in the variable
pricing component under the contract terms and cannot be determined without the
requested data. Met-Ed's purchased power costs from this entity during the first
quarters of 2004 and 2003 were $16 million and $15 million, respectively. Met-Ed
is required to continue to make exhaustive efforts to obtain the necessary
information in future periods and is unable to determine the possible impact of
consolidating any such entity without this information.
127
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
---------------------------
2004 2003
---------- ----------
(In thousands)
OPERATING REVENUES.............................................................. $ 256,445 $ 254,876
---------- ----------
OPERATING EXPENSES AND TAXES:
Purchased power.............................................................. 156,376 155,146
Other operating costs........................................................ 39,908 43,077
---------- ----------
Total operation and maintenance expenses................................. 196,284 198,223
Provision for depreciation and amortization.................................. 25,089 25,337
General taxes................................................................ 16,962 15,744
Income taxes................................................................. 2,563 2,893
---------- ----------
Total operating expenses and taxes....................................... 240,898 242,197
---------- ----------
OPERATING INCOME................................................................ 15,547 12,679
OTHER EXPENSE................................................................... (84) (192)
----------- ----------
INCOME BEFORE NET INTEREST CHARGES.............................................. 15,463 12,487
---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt................................................... 7,447 7,339
Allowance for borrowed funds used during construction........................ (70) (81)
Deferred interest............................................................ 190 (996)
Other interest expense ...................................................... 2,237 143
Subsidiary's preferred stock dividend requirements........................... -- 1,888
---------- ----------
Net interest charges..................................................... 9,804 8,293
---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 5,659 4,194
Cumulative effect of accounting change (net of income taxes of $777,000) (Note 2) -- 1,096
---------- ----------
NET INCOME...................................................................... $ 5,659 $ 5,290
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are
an integral part of these statements.
128
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
-------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $1,976,743 $1,966,624
Less-Accumulated provision for depreciation.................................... 796,606 785,715
---------- ----------
1,180,137 1,180,909
Construction work in progress.................................................. 29,374 29,063
---------- ----------
1,209,511 1,209,972
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Non-utility generation trusts.................................................. 94,660 43,864
Nuclear plant decommissioning trusts........................................... 105,615 102,673
Long-term notes receivable from associated companies........................... 13,865 13,794
Other.......................................................................... 19,117 19,635
---------- ----------
233,257 179,966
--------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 36 36
Receivables-
Customers (less accumulated provisions of $5,872,000 and $5,833,000
respectively, for uncollectible accounts).................................. 117,489 124,462
Associated companies......................................................... 107,346 88,598
Other (less accumulated provisions of $388,000 and $399,000
respectively, for uncollectible accounts).................................. 16,121 15,767
Prepayments and other.......................................................... 49,564 2,511
---------- ----------
290,556 231,374
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 458,560 497,219
Goodwill....................................................................... 894,491 898,547
Accumulated deferred income tax benefits....................................... - 16,642
Other.......................................................................... 19,568 18,523
---------- ----------
1,372,619 1,430,931
---------- ----------
$3,105,943 $3,052,243
========== ==========
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........................................................ 1,215,667 1,215,667
Accumulated other comprehensive loss......................................... (42,180) (42,185)
Retained earnings............................................................ 23,697 18,038
---------- ----------
Total common stockholder's equity.......................................... 1,302,996 1,297,332
Long-term debt and other long-term obligations................................. 588,255 438,764
---------- ----------
1,891,251 1,736,096
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt .............................................. 125,605 125,762
Short-term borrowings-
Associated companies......................................................... 17,185 78,510
Accounts payable-
Associated companies......................................................... 56,391 55,831
Other........................................................................ 28,893 40,192
Accrued taxes................................................................. 2,222 8,705
Accrued interest............................................................... 15,330 12,694
Other.......................................................................... 25,068 21,764
---------- ----------
270,694 343,458
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 7,717 --
Accumulated deferred investment tax credits.................................... 9,691 9,936
Asset retirement obligation.................................................... 106,631 105,089
Nuclear fuel disposal costs.................................................... 19,010 18,968
Power purchase contract loss liability......................................... 629,965 670,482
Retirement benefits............................................................ 147,882 145,081
Other.......................................................................... 23,102 23,133
---------- ----------
943,998 972,689
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
---------- ----------
$3,105,943 $3,052,243
========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are
an integral part of these balance sheets.
129
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
---------------------------
2004 2003
--------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................................. $ 5,659 $ 5,290
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........................... 25,089 25,337
Deferred costs recoverable as regulatory assets....................... (17,993) (11,656)
Deferred income taxes, net............................................ 25,487 (41,640)
Investment tax credits, net........................................... (245) (247)
Accrued retirement benefit obligations................................ 2,802 --
Accrued compensation, net............................................. 2,255 62
Cumulative effect of accounting change (Note 2)....................... -- (1,873)
Receivables........................................................... (12,129) 5,440
Accounts payable...................................................... (10,738) 8,666
Accrued taxes......................................................... (6,483) 27,284
Accrued interest...................................................... 2,636 5,679
Prepayments and other current assets.................................. (47,054) (34,778)
Other................................................................. 3,654 (7,152)
-------- --------
Net cash used for operating activities.............................. (27,060) (19,588)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt.......................................................... 150,000 --
Redemptions and Repayments-
Long-term debt.......................................................... (104) --
Short-term borrowings, net.............................................. (61,326) (90,427)
-------- ---------
Net cash provided from (used for) financing activities.................... 88,570 (90,427)
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................ (11,194) (6,312)
Non-utility generation trusts withdrawals (contributions)................. (50,614) 106,327
Loans to associated companies............................................. (71) --
Other, net................................................................ 369 --
-------- --------
Net cash provided from (used for) investing activities.............. (61,510) 100,015
--------- --------
Net change in cash and cash equivalents...................................... -- (10,000)
Cash and cash equivalents at beginning of period ............................ 36 10,310
-------- --------
Cash and cash equivalents at end of period................................... $ 36 $ 310
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are
an integral part of these statements.
130
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, 2004, and the related
consolidated statements of income and cash flows for each of the three-month
periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change
in its method of accounting for asset retirement obligations as of January 1,
2003 as discussed in Note 1(E) to those consolidated financial statements and
the Company's change in its method of accounting for the consolidation of
variable interest entities as of December 31, 2003 as discussed in Note 8 to
those consolidated financial statements) dated February 25, 2004, we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2003, 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 7, 2004
131
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Penelec is a wholly owned, electric utility subsidiary of FirstEnergy.
Penelec provides regulated transmission and distribution services in western
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 PLR
obligations to customers who elect to retain Penelec as their power supplier.
Results from Operations
- -----------------------
Net income in the first quarter of 2004 increased to $5.7 million,
compared to $5.3 million in the first quarter of 2003. 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 143. Income before
the cumulative effect was $5.7 million in the first three months of 2004,
compared to $4.2 million for the same period of 2003. The increase in net income
was the result of higher operating revenues and lower operating costs --
partially offset by a lower level of deferred interest costs.
Operating revenues increased by $1.6 million or 0.6% in the first
quarter of 2004 compared with the same period in 2003. The higher revenues
resulted from increased distribution revenues offset by lower retail generation
revenues. Revenues from electricity throughput increased by $9 million as a
result of higher unit prices which were partially offset by slightly lower
distribution deliveries compared to the prior year. Penelec's retail generation
kilowatt-hour sales increased 1.5% reflecting higher residential and commercial
sales of 3.5% and 0.5%, respectively. Retail generation sales revenue decreased
$5.3 million reflecting lower unit prices, which offset the generation sales
increase as more customers returned from alternative suppliers. Although
wholesale kilowatt-hour sales increased 121.3%, the volume was minimal for the
first quarters of 2004 and 2003 and revenues increased only slightly.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2004 from the first quarter of 2003 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
---------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ 1.5%
Wholesale............................. 121.3%
-------------------------------------------------
Total Electric Generation Sales......... 1.9%
=================================================
Distribution Deliveries:
Residential........................... 3.4%
Commercial............................ 0.5%
Industrial............................ (4.5)%
--------------------------------------------------
Total Distribution Deliveries........... (0.4)%
==================================================
132
Operating Expenses and Taxes
Total operating expenses and taxes decreased $1 million or 0.5% in the
first quarter of 2004 from the first quarter of 2003, primarily due to lower
other operating costs partially offset by increased purchased power costs and
general taxes. The following table presents changes during the first quarter of
2004 from the same period in 2003 for operating expenses and taxes.
Operating Expenses and Taxes - Changes
-----------------------------------------------------------------
Increase (Decrease) (In millions)
Purchased power ................................. $ 1
Other operating costs............................ (3)
-----------------------------------------------------------------
Total operation and maintenance expenses....... (2)
Provision for depreciation and amortization...... --
General taxes.................................... 1
Income taxes..................................... --
-----------------------------------------------------------------
Total operating expenses and taxes............. $ (1)
=================================================================
Lower other operating costs in the first quarter of 2004, compared
with the same quarter of 2003, were due to reduced postretirement benefit plan
expenses, lower uncollectible customer accounts and transmission expenses.
Purchased power costs increased due primarily to increased PLR purchases from
FES, partially offset by reduced two-party energy purchases. General taxes
increased due to higher payroll taxes from the transfer of employees to Penelec
from GPUS.
Net Interest Charges
Net interest charges increased by $1.5 million in the first quarter of
2004 compared with the first quarter of 2003, reflecting a lower level of
deferred interest costs.
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. The cumulative
adjustment for unrecognized depreciation, accretion offset by the reduction in
the existing decommissioning liabilities and ceasing the accounting practice
depreciating non-regulated generation assets using a cost of removal component
was an $1.9 million increase to income, or $1.1 million net of income taxes.
Capital Resources and Liquidity
- -------------------------------
Penelec's cash requirements in 2004 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
two 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, 2004 and December 31, 2003, Penelec had $36,000 of
cash and cash equivalents.
Cash Flows From Operating Activities
Cash used by operating activities in the first quarter of 2004,
compared with the first quarter of 2003 were as follows:
Operating Cash Flows 2004 2003
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $ 43 $ (25)
Working capital and other............ (70) 5
-------------------------------------------------------------
Total................................ $(27) $ (20)
=============================================================
(1) Includes net income, depreciation and amortization, deferred
costs recoverable as regulatory assets, deferred income
taxes, investment tax credits and pension changes.
Net cash used for operating activities increased to $27 million in the
first quarter of 2004 from $20 million in the same period of 2003. In 2004, the
increase was due to the increase of working capital requirements (primarily from
changes in accounts receivable and payable) offset by an increase in cash
earnings from higher deferred income taxes.
Cash Flows From Financing Activities
Net cash provided from financing activities of $89 million in the
first quarter of 2004 compared to net cash used for financing activities of $90
million in the first quarter of 2003, represents the issuance in March 2004 of
$150 million of long-term debt partially offset by a decrease in short-term
borrowings. The proceeds from the $150 million issuance were used to redeem $125
133
million principal amount of senior notes that matured on April 1, 2004 and to
repay short-term borrowings.
As of March 31, 2004, Penelec had $17 million of short-term
indebtedness, compared to $79 million at the end of 2003. Penelec may borrow
from its affiliates on a short-term basis. Penelec will not issue first mortgage
bonds other than as collateral for senior notes, since its senior note indenture
prohibits (subject to certain exceptions) it from issuing any debt which is
senior to the senior notes. As of March 31, 2004, Penelec had the capability to
issue $6.5 million of additional senior notes based upon first mortgage bond
collateral. Penelec had no restrictions on the issuance of preferred stock.
In March 2004, Penelec completed an on-balance sheet, receivable
financing transaction which allows it to borrow up to $75 million. The borrowing
rate is based on bank commercial paper rates. Penelec is required to pay an
annual facility fee of 0.30% on the entire finance limit. The facility was
undrawn as of March 31, 2004. This facility matures on March 29, 2005.
Penelec's access to capital markets and costs of financing are
dependent on the ratings of its securities and the securities of FirstEnergy.
The ratings outlook on all of its securities is stable.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating replacement power costs and
"demonstrating management's ability to overcome operational challenges."
However, S&P did not change FirstEnergy's ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."
Cash Flows From Investing Activities
Net cash used for investing activities were $62 million in the first
quarter of 2004, compared to net cash provided from investing activities
totaling $100 million in the first quarter of 2003. The net cash used for
investing activities resulted from a refunding payment of $51 million to a NUG
trust fund and increased property additions in 2004. In the first quarter of
2003, net cash provided from investing activities resulted from $106 million of
withdrawals from the NUG trust fund, partially offset by property additions.
Expenditures for property additions primarily support Penelec's energy delivery
operations.
During the remaining quarters of 2004, capital requirements for
property additions are expected to be about $54 million. Penelec has additional
requirements of approximately $125 million for maturing long-term debt during
the remainder of 2004. These cash requirements (excluding debt refinancings) are
expected to be satisfied from internal cash and short-term credit arrangements.
Off-Balance Sheet Arrangements
- ------------------------------
As of March 31, 2004, Penelec's off-balance sheet arrangements
included certain statutory business trusts created by Penelec to issue trust
preferred securities of $92 million. These trusts were included in Penelec's
financial statements prior to the adoption of FIN 46R, but have subsequently
been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities).
This deconsolidation has not resulted in any change in outstanding debt.
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 independent risk oversight function to ensure compliance with corporate risk
management policies and prudent risk management practices.
134
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 2004 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, 2004................... $15 $ -- $15
New contract value when entered............................... -- -- --
Additions/change in value of existing contracts............... -- -- --
Change in techniques/assumptions.............................. -- -- --
Settled contracts............................................. -- -- --
- -----------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (1)... $15 $ -- $15
===============================================================================================
(1) Includes $14 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.
Derivatives included on the Consolidated Balance Sheet as of March 31, 2004:
Non-Hedge Hedge Total
---------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $-- $ -- $--
Non-Current-
Other Deferred Charges............ 15 -- 15
---------------------------------------------------------------------
Net assets........................ $15 $ -- $15
=====================================================================
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 2004 2005 2006 2007 Thereafter Total
- -------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(1)... $ 2 $ 3 $-- $ -- $-- $ 5
Prices based on model................. -- -- 2 2 6 10
- -------------------------------------------------------------------------------------------------
Total(2).......................... $ 2 $ 3 $ 2 $ 2 $ 6 $15
=================================================================================================
(1) Broker quote sheets.
(2) Includes $14 million from an embedded option that is offset by a regulatory
liability and does not affect earnings.
Penelec performs sensitivity analyses to estimate its exposure to the
market risk of its commodity 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, 2004.
Equity Price Risk
Included in Penelec's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $55
million and $54 million as of March 31, 2004 and December 31, 2003,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $6 million reduction in fair value as of March 31, 2004.
135
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 PPUC authorized Penelec'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. 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 FERC 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
$459 million and $497 million as of March 31, 2004 and December 31, 2003,
respectively.
Regulatory Matters
In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate proceedings which approved the
FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy
costs, permitting Penelec to defer, for future recovery, energy costs in excess
of amounts reflected in its capped generation rates retroactive to January 1,
2001. This PLR deferral accounting procedure was later reversed in a February
2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed
the PPUC decision regarding approval of the merger, remanding the decision to
the PPUC only with respect to the issue of merger savings. Penelec established a
$111.1 million reserve in 2002 for its PLR deferred energy costs incurred prior
to its acquisition by FirstEnergy, reflecting the potential adverse impact of
the then pending Pennsylvania Supreme Court decision whether to review the
Commonwealth Court decision. The reserve increased goodwill by an aggregate net
of tax amount of $65.0 million.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the ALJ for hearings, directed Penelec to file a position paper on
the effect of the Commonwealth Court order on the Settlement Stipulation and
allowed other parties to file responses to the position paper. Penelec filed a
letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety
and reinstating Penelec's restructuring settlement previously approved by the
PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Penelec to file tariffs within thirty days of the order to reflect
the CTC rates and shopping credits that were in effect prior to the June 21,
2001 order to be effective upon one day's notice. In response to that order,
Penelec filed these supplements to its tariffs to become effective October 24,
2003.
On October 8, 2003, Penelec filed a petition for clarification
relating to the October 2, 2003 order on two issues: to establish June 30, 2004
as the date to fully refund the NUG trust fund and to clarify that the ordered
accounting treatment regarding the CTC rate/shopping credit swap should follow
the ratemaking, and that the PPUC's findings would not impair its rights to
recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in
the proceedings) petitioned the PPUC to direct Penelec to reinstate accounting
for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several
other parties also filed petitions. On October 16, 2003, the PPUC issued a
reconsideration order granting the date requested by Penelec for the NUG trust
fund refund and, denying Penelec's other clarification requests and granting
ARIPPA's petition with respect to the retroactive accounting treatment of the
changes to the CTC rate/shopping credit swap. On October 22, 2003, Penelec filed
an Objection with the Commonwealth Court asking that the Court reverse the
PPUC's finding that requires Penelec to treat the stipulated CTC rates that were
in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying Penelec's objection without explanation. Due to the vagueness of the
Order, Penelec, on October 31, 2003, filed an Application for Clarification with
the judge. Concurrent with this filing, Penelec, in order to preserve its
rights, also filed with the Commonwealth Court both a Petition for Review of the
PPUC's October 16 and October 22 Orders, and an application for reargument, if
the judge, in his clarification order, indicates that Penelec's objection was
intended to be denied on the merits. In addition to these findings, Penelec, in
compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the
twelve months ended December 31, 2001 and 2002, and for the first two quarters
of 2003, reflecting balances consistent with the PPUC's findings in their
Orders.
136
Effective September 1, 2002, Penelec agreed to purchase a portion of
its PLR requirements from FES through a wholesale power sale agreement. The PLR
sale 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 Penelec under its NUG contracts and other power contracts with
nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure
to high wholesale power prices by providing power at a fixed price for its
uncommitted PLR energy costs during the term of the agreement with FES. FES has
hedged most of 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. Penelec is authorized to continue deferring
differences between NUG contract costs and current market prices.
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. Penelec is
currently awaiting the PPUC to issue a final order in both matters. The order
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports.
On January 16, 2004, the PPUC initiated a formal investigation of
whether Penelec's "service reliability performance deteriorated to a point below
the level of service reliability that existed prior to restructuring" in
Pennsylvania. Discovery has commenced in the proceeding and Penelec's testimony
is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this
investigation and the ALJ has been directed to issue a Recommended Decision by
September 30, 2004, in order to allow the PPUC time to issue a Final Order by
year end of 2004. Penelec is unable to predict the outcome of the investigation
or the impact of the PPUC order.
Environmental Matters
Penelec has been named as a 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, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheets, 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 accrued liabilities
aggregating approximately $30,000 as of March 31, 2004. Penelec accrues
environmental liabilities only when it can conclude that it is probable that an
obligation for such costs exists and can reasonably determine the amount of such
costs. Unasserted claims are reflected in Penelec's determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.
Power Outage
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. On April 5, 2004, the U.S.
- -Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report, the Task Force concluded, among other things, that
the problems leading to the outage began in FirstEnergy's Ohio service area.
Specifically, the final report concludes, among other things, that the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events, including, an alleged failure of both FirstEnergy
and ECAR to assess and understand perceived inadequacies within the FirstEnergy
system; inadequate situational awareness of the developing conditions and a
perceived failure to adequately manage tree growth in certain transmission
rights of way. The Task Force also concluded that there was a failure of the
interconnected grid's reliability organizations (MISO and PJM) to provide
effective diagnostic support. The final report is publicly available through the
Department of Energy's website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th power outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts." Forty-five of those recommendations relate to broad
industry or policy matters while one relates to activities the Task Force
recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has
undertaken several initiatives, some prior to and some since the August 14th
power outage, to enhance reliability which are consistent with these and other
recommendations and believes it will complete those relating to summer 2004 by
June 30 (see Reliability Initiatives below). As many of these initiatives
already were in process and budgeted in 2004, FirstEnergy does not believe that
any incremental expenses associated with additional initiatives undertaken
during 2004 will have a material effect on its operations or financial results.
137
FirstEnergy notes, however, that the applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures.
Reliability Initiatives
On October 15, 2003, NERC issued a Near Term Action Plan that
contained recommendations for all control areas and reliability coordinators
with respect to enhancing system reliability. Approximately 20 of the
recommendations were directed at the FirstEnergy companies and broadly focused
on initiatives that are recommended for completion by summer 2004. These
initiatives principally relate to changes in voltage criteria and reactive
resources management; operational preparedness and action plans; emergency
response capabilities; and, preparedness and operating center training.
FirstEnergy presented a detailed compliance plan to NERC, which NERC
subsequently endorsed on May 7, 2004, and the various initiatives are expected
to be completed no later than June 30, 2004.
On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review control area operations throughout much of the United States
during 2004, is an independent review to identify areas for improvement. The
final audit report was completed on April 30, 2004. The report identified
positive observations and included various recommendations for improvement.
FirstEnergy is currently reviewing the audit results and recommendations and
expects to implement those relating to summer 2004 by June 30. Based on its
review thus far, FirstEnergy believes that none of the recommendations identify
a need for any incremental material investment or upgrades to existing
equipment. FirstEnergy notes, however, that NERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures.
On March 1, 2004, certain FirstEnergy companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S. - Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergy's control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with FERC the results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things, the reliability of the transmission grid in critical points
in the Northern Ohio area and the need, if any, for reactive power
reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing
the results of that study and expects to complete the implementation of
recommendations relating to 2004 by this summer. Based on its review thus far,
FirstEnergy believes that the study does not recommend any incremental material
investment or upgrades to existing equipment. FirstEnergy notes, however, that
FERC or other applicable government agencies and reliability coordinators may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
With respect to each of the foregoing initiatives, FirstEnergy has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.
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.
Critical Accounting Policies
Penelec prepares its consolidated financial statements in accordance
with GAAP. Application of these principles often requires a high degree of
judgment, estimates and assumptions that affect financial results. All of
Penelec's assets are subject to their own specific risks and uncertainties and
are regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting these specific factors. Penelec's more significant
accounting policies are described below.
Regulatory Accounting
Penelec is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on costs that the regulatory agencies
determine Penelec is permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Pennsylvania, a significant
amount of regulatory assets have been recorded - $459 million as of March 31,
2004. Penelec regularly reviews these assets to assess their ultimate
138
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
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, Penelec enters into commodity
contracts, as well as interest rate swaps, which increase the impact of
derivative accounting judgments.
Revenue Recognition
Penelec follows the accrual method of accounting for revenues,
recognizing revenue for electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
electricity sales to individual customers is based on meter readings, which
occur on a systematic basis throughout the month. At the end of each month,
electricity delivered to customers since the last meter reading is estimated and
a corresponding accrual for unbilled revenues is recognized. The determination
of unbilled revenues requires management to make estimates regarding electricity
available for retail load, transmission and distribution line losses,
consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
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. In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first
quarter of 2004 were computed assuming a 9.0% rate of return on plan assets
based upon projections of future returns and its pension trust investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund its pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2004 and 2003 composite health care trend rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
139
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 144, Penelec periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset might 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 has
occurred, Penelec recognizes a loss - calculated as the difference between the
carrying value and the estimated fair value of the asset (discounted future net
cash flows).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, Penelec recognizes an ARO for the future
decommissioning of TMI-2. The ARO liability represents an estimate of the fair
value of Penelec's current obligation related to nuclear decommissioning. A fair
value measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. Penelec used an expected cash flow approach (as
discussed in FASB Concepts Statement No. 7 to measure the fair value of the
nuclear decommissioning ARO. This approach applies probability weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.
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, Penelec
evaluates 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), the goodwill is tested for
impairment. If impairment were to be indicated Penelec would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill. Penelec's annual review was completed in the
third quarter of 2003, with no impairment indicated. The forecasts used in
Penelec's 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. In the first
quarter of 2004, Penelec reduced goodwill by $4 million for interest received on
a pre-merger income tax refund. As of March 31, 2004, Penelec had $894 million
of goodwill.
New Accounting Standards and Interpretations
FSP 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Act. FirstEnergy elected to defer the effects of the Medicare Act due to the
lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting
for the effects of the Medicare Act effective January 1, 2004 as a result of a
February 2, 2004 plan amendment that required remeasurement of the plan's
obligations. See Note 2 for a discussion of the effect of the federal subsidy
and plan amendment on the consolidated financial statements.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, Penelec adopted FIN 46R for interests in VIEs commonly
referred to as special-purpose entities effective December 31, 2003 and for all
other types of entities effective March 31, 2004. Adoption of FIN 46R did not
have a material impact on Penelec's financial statements for the quarter ended
March 31, 2004. See Note 2 for a discussion of Variable Interest Entities.
140
For the quarter ended March 31, 2004, Penelec evaluated, among other
entities, its power purchase agreements and determined that it is possible that
two NUG entities might be considered variable interest entities. Penelec has
requested but not received the information necessary to determine whether these
entities are VIEs or whether Penelec is the primary beneficiary. In most cases,
the requested information was deemed to be competitive and proprietary data. As
such, Penelec applied the scope exception that exempts enterprises unable to
obtain the necessary information to evaluate entities under FIN 46R. The maximum
exposure to loss from these entities results from increases in the variable
pricing component under the contract terms and cannot be determined without the
requested data. The cost of purchased power from these entities was $7 million
in each of the quarters ended March 31, 2004 and 2003. Penelec is required to
continue to make exhaustive efforts to obtain the necessary information in
future periods and is unable to determine the possible impact of consolidating
any such entity without this information.
141
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------
See "Management's Discussion and Analysis of Results of Operation and
Financial Condition - Market Risk Information" in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
- --------------------------------
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The applicable 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-15(e) and 15d-15(e), as of the end of the date covered by this report. 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 material information relating to the registrant and its
consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31, 2004, there were no changes in the
registrants' internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, the registrants'
internal control over financial reporting.
142
PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
-----------------
Reference is made to Note 3, Commitments, Guarantees and
Contingencies, of the Notes to Consolidated Financial Statements contained in
Part I, Item 1 for a description of certain legal proceedings.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits
Exhibit
Number
------
Met-Ed
------
12 Fixed charge ratios
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
Penelec
-------
12 Fixed charge ratios
15 Letter from independent accountants
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chie
financial officer, pursuant to 18 U.S.C. Section 1350.
JCP&L
-----
12 Fixed charge ratios
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.3 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.2 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
FirstEnergy
-----------
10-40 Employment, severance and change in control agreement
between FirstEnergy Corp.
and A. J. Alexander, dated February 17, 2004.
15 Letter from independent accountants
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
OE and Penn
-----------
15 Letter from independent accountants
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
CEI and TE
----------
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
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.
143
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, CEI and TE
-----------------------
FirstEnergy, CEI and TE each filed the following four reports on Form
8-K since December 31, 2003: A report dated January 13, 2004 reported
FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report dated
January 20, 2004 reported Anthony J. Alexander elected as FirstEnergy Chief
Executive Officer and George M. Smart elected as FirstEnergy Chairman of the
Board of Directors. A report dated February 9, 2004 reported Moody's lowered
debt ratings for FirstEnergy and subsidiaries. A report dated March 8, 2004
reported that FirstEnergy began Davis-Besse restart with NRC authorization.
OE, Penn, JCP&L, Met-Ed and Penelec
-----------------------------------
OE, Penn, JCP&L, Met-Ed and Penelec each filed the following three
reports on Form 8-K since December 31, 2003: A report dated January 13, 2004
reported FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report
dated January 20, 2004 reported Anthony J. Alexander elected as FirstEnergy
Chief Executive Officer and George M. Smart elected as FirstEnergy Chairman of
the Board of Directors. A report dated February 9, 2004 reported Moody's lowered
debt ratings for FirstEnergy and subsidiaries.
144
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 10, 2004
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
145