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 June 30, 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 AUGUST 6, 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, with
respect to FirstEnergy Corp. and the Ohio registrants, the final outcome in the
proceeding related to the registrants' Application for a 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 (as amended) 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................................................ 1-23
FirstEnergy Corp.
Consolidated Statements of Income......................................................... 24
Consolidated Statements of Comprehensive Income........................................... 25
Consolidated Balance Sheets............................................................... 26
Consolidated Statements of Cash Flows..................................................... 27
Report of Independent Registered Public Accounting Firm................................... 28
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 29-60
Ohio Edison Company
Consolidated Statements of Income and Comprehensive Income................................ 61
Consolidated Balance Sheets............................................................... 62
Consolidated Statements of Cash Flows..................................................... 63
Report of Independent Registered Public Accounting Firm................................... 64
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 65-75
The Cleveland Electric Illuminating Company
Consolidated Statements of Income and Comprehensive Income................................ 76
Consolidated Balance Sheets............................................................... 77
Consolidated Statements of Cash Flows..................................................... 78
Report of Independent Registered Public Accounting Firm................................... 79
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 80-90
The Toledo Edison Company
Consolidated Statements of Income and Comprehensive Income................................ 91
Consolidated Balance Sheets............................................................... 92
Consolidated Statements of Cash Flows..................................................... 93
Report of Independent Registered Public Accounting Firm................................... 94
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 95-105
Pennsylvania Power Company
Consolidated Statements of Income and Comprehensive Income................................ 106
Consolidated Balance Sheets............................................................... 107
Consolidated Statements of Cash Flows..................................................... 108
Report of Independent Registered Public Accounting Firm................................... 109
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 110-117
TABLE OF CONTENTS (Cont'd)
Pages
Jersey Central Power & Light Company
Consolidated Statements of Income and Comprehensive Income................................ 118
Consolidated Balance Sheets............................................................... 119
Consolidated Statements of Cash Flows..................................................... 120
Report of Independent Registered Public Accounting Firm................................... 121
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 122-131
Metropolitan Edison Company
Consolidated Statements of Income and Comprehensive Income................................ 132
Consolidated Balance Sheets............................................................... 133
Consolidated Statements of Cash Flows..................................................... 134
Report of Independent Registered Public Accounting Firm................................... 135
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 136-145
Pennsylvania Electric Company
Consolidated Statements of Income and Comprehensive Income................................ 146
Consolidated Balance Sheets............................................................... 147
Consolidated Statements of Cash Flows..................................................... 148
Report of Independent Registered Public Accounting Firm................................... 149
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 150-159
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................ 160
Item 4. Controls and Procedures............................................................... 160
Part II. Other Information
Item 1. Legal Proceedings..................................................................... 161
Item 4. Submission of Matters to a Vote of Security Holders................................... 161-162
Item 6. Exhibits and Reports on Form 8-K...................................................... 162-163
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to
identify FirstEnergy Corp. and its current and former 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
Companies................OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
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 JCP&L, Met-Ed and Penelec,
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, previously held
FirstEnergy's interest in GLEP
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., formerly a MARBEL
subsidiary
OE.......................Ohio Edison Company, an Ohio electric utility operating
subsidiary
OE Companies.............OE and Penn
Penelec..................Pennsylvania Electric Company, a Pennsylvania electric
utility operating subsidiary
Penn.....................Pennsylvania Power Company, a Pennsylvania electric
utility operating subsidiary of OE
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
TE.......................The Toledo Edison Company, an Ohio electric utility
operating subsidiary
TEBSA....................Termobarranquilla S.A., Empresa de Servicios Publicos
TECC.....................Toledo Edison Capital Corporation, a 90% owned
subsidiary of TE
The following abbreviations and acronyms are used to identify
frequently used terms in this report:
ALJ......................Administrative Law Judge
AOCL.....................Accumulated Other Comprehensive Loss
APB......................Accounting Principles Board
APB 25...................APB Opinion No. 25, "Accounting for Stock Issued to
Employees"
ARB 51...................Accounting Research Bulletin No. 51, "Consolidated
Financial Statements"
ARO......................Asset Retirement Obligation
ASLB.....................Atomic Safety and Licensing Board
BGS......................Basic Generation Service
CO2......................Carbon Dioxide
CTA......................Currency Translation Adjustment
CTC......................Competitive Transition Charge
ECAR.....................East Central Area Reliability Agreement
EITF.....................Emerging Issues Task Force
EITF 03-1................EITF Issue No. 03-1, "The Meaning of Other-Than-
Temporary and Its Application to Certain Investments"
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"
i
EPA......................Environmental Protection Agency
FASB.....................Financial Accounting Standards Board
FCON 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"
FMB......................First Mortgage Bonds
FSP......................FASB Staff Position
FSP 106-1................FASB Staff Position 106-1, "Accounting and Disclosure
Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act
of 2003"
FSP 106-2................FASB Staff Position 106-2, "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
HVAC.....................Heating, Ventilation and Air-conditioning
IRS......................Internal Revenue Service
ISO......................Independent System Operator
KWH......................Kilowatt-hours
LOC......................Letter of Credit
MACT.....................Maximum Achievable Control Technologies
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
MTN......................Medium Term Note
MW.......................Megawatts
NAAQS....................National Ambient Air Quality Standards
NERC.....................North American Electric Reliability Council
NJBPU....................New Jersey Board of Public Utilities
NOV......................Notices of Violation
NOX......................Nitrogen Oxide
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......................United States 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 95..................SFAS No. 95, "Statement of Cash Flows"
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
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 "EUOC."
The utility subsidiaries excluding ATSI, which is not a registrant, are referred
to throughout as the "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 and MYR.
FirstEnergy and its subsidiaries follow GAAP and comply with the
regulations, orders, policies and practices prescribed by the SEC, FERC and, as
applicable, PUCO, PPUC and NJBPU. The 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. As
discussed in Note 8, segment reporting in 2003 was reclassified to conform with
the current year business segment organizations and operations. In addition,
revenues, expenses and taxes related to certain divestitures in 2003 have been
reclassified and reported net as 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 registered public
accounting firm has performed reviews of, and issued reports on, these
consolidated interim financial statements in accordance with standards
established by the Public Company Accounting Oversight Board (United States).
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 registered public accounting firm'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 VIEs 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 VIEs where
they have determined that they are the primary beneficiary as defined by FIN
46R.
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 by CEI impacted the financial
statements of CEI and TE but had no impact on the consolidated 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 June 30, 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 and leaseback
agreements, OE, CEI and TE have net minimum discounted lease payments of $680
million, $111 million and $561 million, respectively, that would not be payable
if the casualty value payments are made. As of June 30, 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 - $759 million and TE - $305
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. On June 1, 2004, Met-Ed extinguished the subordinated debentures
held by its affiliated trust and redeemed all of the associated 7.35% trust
preferred securities (aggregate value $100 million). On July 30, 2004, Penelec
announced that it will redeem 100% of its affiliated trust's 7.34% preferred
securities (aggregate value of $100 million) effective September 1, 2004.
Penelec has effectively provided a full and unconditional guarantee of
obligations under the trust's preferred securities.
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 June 30, 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.
FirstEnergy has evaluated 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
2
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,
neither JCP&L, Met-Ed or Penelec 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. 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. The
purchased power costs from these entities during the three and six months ended
June 30, 2004 and 2003 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
-----------------------------------------------
2004 2003 2004 2003
- ------------------------------------------------------------------------------
(In millions)
JCP&L................... $35 $25 $ 63 $58
Met-Ed.................. 9 11 25 27
Penelec................. 6 6 13 13
--- --- ---- ---
Total................ $50 $42 $101 $98
=== === ==== ===
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 during the respective period as the
denominator. The denominator for diluted earnings per share reflects the
weighted average of common shares outstanding plus the potential additional
common shares that could result if dilutive securities and agreements were
exercised. Stock-based awards to purchase shares of common stock totaling 3.3
million in each of the second quarter and first six months of 2004 and 0.5
million and 3.5 million in the second quarter and first six months of 2003,
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 Six Months Ended
Reconciliation of Basic and June 30, June 30,
------------------------------------------------
Diluted Earnings per Share 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------
(In thousands)
Income before discontinued operations and
cumulative effect of accounting change........... $204,045 $ 10,335 $378,044 $124,715
Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share
(weighted average shares outstanding)......... 327,284 294,166 327,171 294,026
Assumed exercise of dilutive stock options
and awards.................................. 1,819 1,722 1,890 1,329
------------------------------------------------------------------------------------------------------
Denominator for diluted earnings per share......... 329,103 295,888 329,061 295,355
======================================================================================================
Income Before Discontinued Operations and
Cumulative Effect ofAccounting Change,
per common share:
Basic......................................... $0.62 $0.03 $1.16 $0.43
Diluted....................................... $0.62 $0.03 $1.15 $0.42
------------------------------------------------------------------------------------------------------
3
Preferred Stock Subject to Mandatory Redemption
Long-term debt includes the preferred stock of consolidated
subsidiaries subject to mandatory redemption as of June 30, 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
preferred dividends on their manditorily redeemable preferred stock in interest
expense for the quarter and six months ended June 30, 2003, but have included
the dividends in interest charges for the quarter and six months ended June 30,
2004.
Securitized Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L
include the results 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 FirstEnergy's and JCP&L's Consolidated
Balance Sheets. The transition bonds are obligations of JCP&L Transition only
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 the
fluctuation of interest rates and commodity prices, including electricity,
natural gas and coal. To manage the volatility relating to these exposures,
FirstEnergy uses a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes, and to a lesser extent,
for trading purposes. FirstEnergy's Risk Policy Committee, comprised of
executive officers, exercises an independent risk oversight function to ensure
compliance with corporate risk management policies and prudent risk management
practices.
FirstEnergy uses derivatives to hedge the risk of price and interest
rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash
flow hedges of electricity and natural gas purchases. The maximum periods over
which the variability of electricity and natural gas cash flows are hedged are
two and three years, respectively. Gains and losses from hedges of commodity
price risks are included in net income when the underlying hedged commodities
are delivered. Also, 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 June 30, 2004 and March 31, 2004 was
$100 million and $111 million, respectively. The decrease resulted from the sale
of GLEP (see Note 5). Approximately $11 million (after tax) of the net deferred
loss on derivative instruments in AOCL as of June 30, 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 second quarter of 2004, FirstEnergy executed
fixed-for-floating interest rate swap agreements with an aggregate notional
amount of $350 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 $350 million notional
amount of its subsidiaries' senior notes and subordinated debentures having a
weighted average fixed interest rate of 5.89%; the interest rate swap agreements
have effectively converted that
4
rate to a current weighted average variable rate of 2.42%. The notional values
of interest rate swap agreements increased to $1.70 billion as of June 30, 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
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 June 30, 2004, FirstEnergy had $6.1 billion of goodwill that
primarily relates to its regulated services segment. In the first six months of
2004, FirstEnergy adjusted goodwill related to the former GPU companies for
interest received on a pre-merger income tax refund and for the reversal of tax
valuation allowances related to income tax benefits realized attributable to
prior period capital loss carryforwards that were offset by capital gains
generated in 2004. A summary of the change in goodwill during the six months
ended June 30, 2004 is shown below:
FirstEnergy CEI TE JCP&L Met-Ed Penelec
- --------------------------------------------------------------------------------------------------------
Goodwill Reconciliation (In millions)
Balance as of December 31, 2003 ......... $6,128 $1,694 $505 $2,001 $884 $899
Adjustments related to GPU acquisition. (27) -- -- (5) (7) (15)
------ ------ ---- ------ ---- ----
Balance as of June 30, 2004.............. $6,101 $1,694 $505 $1,996 $877 $884
====== ====== ==== ====== ==== ====
Asset Retirement Obligations
FirstEnergy recognizes a liability for retirement obligations
associated with tangible assets in accordance with SFAS 143. 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 $1.217 billion as of June 30, 2004 and included
$1.203 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 FCON 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 June 30, 2004, the fair value of the decommissioning
trust assets was $1.425 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 tables provide the beginning and ending aggregate
carrying amount of the ARO and the changes to the balance during the three
months and six months ended June 30, 2004 and 2003, respectively.
Three Months Ended FirstEnergy OE CEI TE Penn JCP&L Met-Ed Penelec
- ----------------------------------------------------------------------------------------------------------------------
ARO Reconciliation (In millions)
Balance, April 1, 2004............ $1,198 $ 191 $ 259 $ 185 $ 132 $ 111 $ 213 $ 107
Liabilities incurred.............. -- -- -- -- -- -- -- --
Liabilities settled............... -- -- -- -- -- -- -- --
Accretion......................... 19 3 4 3 2 2 3 2
Revisions in estimated cash flows. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Balance, June 30, 2004............ $1,217 $ 194 $ 263 $ 188 $ 134 $ 113 $ 216 $ 109
====== ====== ====== ====== ====== ====== ====== ======
Balance, April 1, 2003............ $1,126 $ 179 $ 242 $ 175 $ 123 $ 105 $ 201 $ 101
Liabilities incurred.............. -- -- -- -- -- -- -- --
Liabilities settled............... -- -- -- -- -- -- -- --
Accretion ........................ 19 3 4 3 3 2 3 1
Revisions in estimated cash flows. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Balance, June 30, 2003............ $1,145 $ 182 $ 246 $ 178 $ 126 $ 107 $ 204 $ 102
====== ====== ====== ====== ====== ====== ====== ======
5
Six Months Ended FirstEnergy OE CEI TE Penn JCP&L Met-Ed Penelec
- -----------------------------------------------------------------------------------------------------------------------
ARO Reconciliation (In millions)
Balance, January 1, 2004.......... $1,179 $ 188 $ 255 $ 182 $ 130 $ 109 $ 210 $ 106
Liabilities incurred.............. -- -- -- -- -- -- -- --
Liabilities settled............... -- -- -- -- -- -- -- --
Accretion......................... 38 6 8 6 4 4 6 3
Revisions in estimated cash flows. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Balance, June 30, 2004............ $1,217 $ 194 $ 263 $ 188 $ 134 $ 113 $ 216 $ 109
====== ====== ====== ====== ====== ====== ====== ======
Balance, January 1, 2003.......... $1,109 $ 176 $ 238 $ 172 $ 122 $ 104 $ 198 $ 99
Liabilities incurred.............. -- -- -- -- -- -- -- --
Liabilities settled............... -- -- -- -- -- -- -- --
Accretion......................... 36 6 8 6 4 3 6 3
Revisions in estimated cash flows. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Balance, June 30, 2003............ $1,145 $ 182 $ 246 $ 178 $ 126 $ 107 $ 204 $ 102
====== ====== ====== ====== ====== ====== ====== ======
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 FirstEnergy and the Companies on January 1, 2005. FirstEnergy
will not be able to determine the exact impact of the proposed standard until it
is issued in final form. The table below summarizes the effects on the Company's
net income and earnings per share had the Company applied the fair value
recognition provisions of SFAS 123 to stock-based employee compensation in the
current reporting periods.
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2004 2003 2004 2003
---- ---- ---- ----
(In thousands) (In thousands)
Net income (loss), as reported........... $204,045 $(57,888) $378,044 $160,614
Add back compensation expense
reported in net income, net of tax
(based on APB 25)...................... -- 49 -- 91
Deduct compensation expense based
upon estimated fair value, net of tax.. (4,770) (3,731) (9,023) (6,713)
-------------------------------------------------------------------------------------------------
Adjusted net income (loss)............... $199,275 $(61,570) $369,021 $153,992
-------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock -
Basic
As Reported......................... $0.62 $(0.20) $1.16 $0.55
Adjusted............................ $0.61 $(0.21) $1.13 $0.52
Diluted
As Reported......................... $0.62 $(0.20) $1.15 $0.54
Adjusted............................ $0.61 $(0.21) $1.12 $0.52
Discontinued Operations
FirstEnergy's discontinued operations in the second quarter and the
first six months of 2003 consisted of net losses aggregating $68 million and $66
million, respectively, 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 six months ended June 30, 2003 and reported as a net amount 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. As a result of the abandonment, FirstEnergy recognized a one-time,
non-cash charge of $67 million (no income tax benefit was recognized), or $0.23
per share of common stock in the second quarter of 2003. This charge resulted
from realizing CTA losses through earnings ($90 million, or $0.30 per share
6
of common stock), partially offset by the gain recognized from abandoning
FirstEnergy's investment in Emdersa ($22 million, or $0.07 per share of common
stock). Since FirstEnergy had previously recorded $90 million of CTA adjustments
in OCI, the net effect of the $67 million charge was an increase in common
stockholders' equity of $22 million. 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, FirstEnergy
recorded asset retirement costs 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 three months and six months ended June 30, 2003.
The impact of adopting SFAS 143 on the financial statements of each
of the Companies effective January 1, 2003, is shown in the table below:
OE CEI TE Penn JCP&L Met-Ed Penelec
- ---------------------------------------------------------------------------------------------------------------
(In millions)
Asset retirement costs .............. $134 $ 50 $ 41 $ 78 $ 98 $186 $93
Accumulated depreciation............. 25 7 6 9 98 186 93
Asset retirement obligation.......... 298 238 172 121 104 198 99
Cumulative effect adjustment, pretax. 54 73 44 18 - 0.4 2
Cumulative effect adjustment, net
of tax 32 42 26 11 - 0.2 1
Restatements of TE, JCP&L and Penelec Previously Reported Quarterly
Results
Earnings for the three months and six months ended June 30, 2003 have
been restated for TE, JCP&L and Penelec 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 subsequently
capitalized to construction, were $0.6 million ($0.3 million after-tax) and $1.0
million ($0.6 million after-tax) in the second quarter and the first six months
of 2003, respectively. TE's interest expense was overstated by $0.3 million
($0.2 million after-tax) and $1.3 million ($0.7 million after-tax) in the second
quarter and the first six months of 2003, respectively. Similar to TE, JCP&L's
capital costs originally recorded as operating expenses were $3.0 million ($1.8
million after-tax) and $3.2 million ($1.9 million after-tax) in the second
quarter and the first six months of 2003, respectively. Penelec's capital costs
originally recorded as operating expenses were $0.7 million ($0.4 million
after-tax) in the second quarter and the first six months of 2003. The impacts
of these adjustments were not material to the consolidated balance sheets or
consolidated statements of cash flows for TE, JCP&L or Penelec for any quarter
of 2003.
The effects of these adjustments on the consolidated statements of
income previously reported for TE, JCP&L and Penelec for the three months and
six months ended June 30, 2003 are as follows:
7
TE
- --
Three Months Ended Six Months Ended
June 30, 2003 June 30, 2003
---------------------------- -----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- -------- ------------- --------
(In thousands)
Operating revenues......................... $215,988 $215,988 $447,810 $447,810
Operating expenses......................... 218,068 217,865 444,413 444,366
-------- -------- -------- --------
Operating income (loss).................... (2,080) (1,877) 3,397 3,444
Other income............................... 3,776 3,776 6,876 6,876
Net interest charges....................... 11,408 11,060 21,385 20,110
-------- -------- -------- --------
Income (loss) before cumulative effect
of accounting change.................... (9,712) (9,161) (11,112) (9,790)
Cumulative effect of accounting change..... -- -- 25,550 25,550
-------- -------- -------- --------
Net income (loss).......................... (9,712) (9,161) 14,438 15,760
Preferred stock dividend requirements...... 2,211 2,211 4,416 4,416
-------- -------- -------- --------
Earnings (loss) attributable to
common stock............................ $(11,923) $(11,372) $ 10,022 $ 11,344
======== ======== ======== ========
JCP&L
- -----
Three Months Ended Six Months Ended
June 30, 2003 June 30, 2003
---------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- -------- ------------- --------
(In thousands)
Operating revenues......................... $542,771 $542,771 $1,199,723 $1,199,723
Operating expenses......................... 566,269 564,506 1,148,013 1,146,115
-------- -------- ---------- ----------
Operating income (loss).................... (23,498) (21,735) 51,710 53,608
Other income............................... 2,264 2,264 3,440 3,440
Net interest charges....................... 22,410 22,410 44,912 44,912
-------- -------- ---------- ----------
Net income (loss).......................... (43,644) (41,881) 10,238 12,136
Preferred stock dividend requirements...... (488) (488) (363) (363)
-------- -------- ---------- ----------
Earnings (loss) attributable to
common stock............................ $(43,156) $(41,393) $ 10,601 $ 12,499
========= ======== ========== ==========
Penelec
- -------
Three Months Ended Six Months Ended
June 30, 2003 June 30, 2003
----------------------------- -----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
---------------- --------- ------------- ---------
(In thousands)
Operating revenues......................... $231,926 $231,926 $486,802 $486,802
Operating expenses......................... 216,044 215,638 458,241 457,835
-------- -------- -------- --------
Operating income........................... 15,882 16,288 28,561 28,967
Other income............................... 534 534 342 342
Net interest charges....................... 8,112 8,112 16,405 16,405
-------- -------- -------- --------
Income before cumulative effect
of accounting change.................... 8,304 8,710 12,498 12,904
Cumulative effect of accounting change..... -- -- 1,096 1,096
-------- -------- -------- --------
Net income ................................ $ 8,304 $ 8,710 $ 13,594 $ 14,000
======== ======== ======== ========
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 $708 million
(OE-$108 million, CEI-$91 million, TE-$48 million, Penn-$64 million, JCP&L-$142
million, Met-Ed-$53 million, Penelec-$60 million, ATSI-$24 million, FES-$81
million and other subsidiaries-$37 million) is applicable to 2004. Investments
for additional nuclear fuel during the 2004-2006 period are estimated to be
approximately $300 million (OE-$84 million, CEI-$98 million, TE-$63 million and
Penn-$55 million), of which approximately $82 million (OE-$26 million, CEI-$26
million, TE-$11 million and Penn-$19 million) applies to 2004.
8
Guarantees and Other Assurances
As part of normal business activities, FirstEnergy and the Companies
enter into various agreements to provide financial or performance assurances to
third parties. As of June 30, 2004, outstanding guarantees and other assurances
aggregated $2.1 billion and included contract guarantees ($1.0 billion), surety
bonds ($0.3 billion) and letters of credit ($0.8 billion).
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 $0.9 billion (included in the $1.0
billion discussed above) as of June 30, 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.
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 June 30, 2004:
Collateral Paid
Total ---------------------------- Remaining
Collateral Provisions Exposure(1) Cash Letters of Credit Exposure
--------------------------------------------------------------------------------------
(In millions)
Rating downgrade.......... $270 $161 $18 $ 91
Adverse event............. 180 -- 23 157
-------------------------------------------------------------------------------------
Total..................... $450 $161 $41 $248
=====================================================================================
(1)As of July 12, 2004, FirstEnergy's total exposure decreased to
$437 million and the remaining exposure decreased to $240
million - net of $156 million of cash collateral and $41
million of letters of credit collateral provided to
counterparties.
Most of FirstEnergy's surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees of $257 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 LOC
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.
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
9
period. The Companies cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy.
The Companies believe they are 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) were required to comply by May 31, 2004
with individual state NOx budgets. New Jersey and Pennsylvania submitted a SIP
that required compliance with the state NOx budgets at the Companies' New Jersey
and Pennsylvania facilities by May 1, 2003. Michigan and Ohio submitted a SIP
that required compliance with the state NOx budgets at the Companies' Michigan
and Ohio facilities by May 31, 2004. The Companies believe their facilities are
complying with the state NOx budgets through combustion controls and
post-combustion controls, including Selective Catalytic Reduction and Selective
Non-Catalytic Reduction systems, and/or using emission allowances.
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 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 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. These cases are referred to as New Source Review cases. 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 trial to address civil penalties and what, if any,
actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated, in its August 2003
ruling, 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
10
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. While the parties are engaged in meaningful
settlement discussions, management is unable to predict the ultimate outcome of
this matter and no liability has been accrued as of June 30, 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 June 30, 2004, based on estimates of the total
costs of cleanup, the Companies' proportionate responsibility for such costs and
the financial ability of other nonaffiliated entities to pay. In addition, JCP&L
has accrued liabilities for environmental remediation of former manufactured gas
plants in New Jersey; those costs are being recovered by JCP&L through a
non-bypassable SBC. Included in Current Liabilities and Other Noncurrent
Liabilities are accrued liabilities aggregating approximately $65 million (JCP&L
- - $45.8 million, CEI - $2.4 million, TE - $0.2 million, Met-Ed - $29,000,
Penelec - $26,000, and other - $16.8 million) as of June 30, 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 wave
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
11
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 were appealed to the Appellate Division. The Appellate Court
issued a decision on July 8, 2004, affirming the decertification of the
originally certified class but remanding for certification of a class limited to
those customers directly impacted by the outages of transformers in Red Bank,
New Jersey. On July 28, 2004, both plaintiffs and JCP&L appealed the decision of
the Appellate Division to the New Jersey Supreme Court. FirstEnergy is unable to
predict the outcome of these matters and no liability has been accrued as of
June 30, 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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Regulatory Matters
below). FirstEnergy's implementation of these recommendations included
completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 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. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004.
As part of its informal inquiry, which began in September 2003, the
SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy
voluntarily provide information and documents related to the Davis-Besse outage.
FirstEnergy is complying with this request and continues to cooperate fully with
this inquiry. 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, including claims for asbestos exposure, 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.
12
Various legal proceedings alleging violations of federal securities
laws and related state laws were 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. The lawsuits were filed against FirstEnergy and certain of its officers
and directors. On July 27, 2004, FirstEnergy announced that it had reached an
agreement to resolve these pending lawsuits. The settlement agreement, which
does not constitute any admission of wrongdoing, provides for a total settlement
payment of $89.9 million. Of that amount, FirstEnergy's insurance carriers will
pay $71.92 million, based on a contractual pre-allocation, and FirstEnergy will
pay $17.98 million, which resulted in a charge against FirstEnergy's second
quarter 2004 earnings of $0.03 per share of common stock. The federal securities
cases were consolidated into a single action, as were the federal derivative
cases; those actions are pending in federal court in Akron. Two state court
derivative cases are also pending. The settlement is subject to court approval
and, although not anticipated to occur, in the event that a significant number
of shareholders do not accept the terms of the settlement, FirstEnergy and
individual defendants have the right, but not the obligation, to set aside the
settlement and recommence the litigation.
FirstEnergy's Ohio utility subsidiaries were 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.
4 - PENSION AND OTHER POSTRETIREMENT BENEFITS:
The components of FirstEnergy's net periodic pension cost, including
amounts capitalized, consisted of the following:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- -----------------
Pension Benefits 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------
(In millions)
Service cost .................................... $ 19 $ 17 $ 39 $ 34
Interest cost.................................... 63 65 126 129
Expected return on plan assets................... (71) (64) (143) (127)
Amortization of prior service cost............... 2 2 4 5
Recognized net actuarial loss.................... 10 16 20 32
------- ------- ------- -------
Net periodic cost................................ $ 23 $ 36 $ 46 $ 73
====== ====== ====== ======
The components of FirstEnergy's net periodic other postretirement
benefit cost, including amounts capitalized, consisted of the following:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- -----------------
Other Postretirement Benefits 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------
(In millions)
Service cost .................................... $ 8 $ 16 $ 19 $ 33
Interest cost.................................... 25 96 56 193
Expected return on plan assets................... (10) (95) (22) (190)
Amortization of prior service cost............... (8) 4 (19) 7
Recognized net actuarial loss.................... 9 24 20 48
------ ------- ------- -------
Net periodic cost................................ $ 24 $ 45 $ 54 $ 91
====== ====== ====== ======
FirstEnergy contributed $17 million to its other postretirement
benefit plans in the six months ended June 30, 2004. The Company has no funding
requirements for the remainder of 2004. FirstEnergy did not contribute to its
pension plans during the first six months of 2004 and has no funding
requirements for the remainder of 2004.
Pension and postretirement benefit obligations are allocated to the
subsidiaries employing the plan participants. The Companies capitalize employee
benefits related to construction projects. The net periodic pension costs,
13
including amounts capitalized, recognized by each of the Companies in the three
and six months ended June 30, 2004 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- -----------------
Pension Benefit Cost 2004 2003 2004 2003
-----------------------------------------------------------------------------------------------------
(In millions)
OE .............................................. $ 1.8 $ 2.9 $ 3.5 $ 5.8
Penn............................................. 0.1 0.4 0.2 0.9
CEI.............................................. 1.6 2.1 3.2 4.2
TE............................................... 0.8 1.1 1.6 2.1
JCP&L............................................ 1.9 5.3 3.7 11.0
Met-Ed........................................... - 2.6 0.1 5.7
Penelec.......................................... 0.1 3.1 0.2 6.6
The net periodic postretirement benefit costs, including amounts
capitalized, recognized by each of the Companies in the three and six months
ended June 30, 2004 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -----------------
Other Postretirement Benefit Cost 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------
(In millions)
OE .............................................. $ 4.9 $ 5.0 $12.0 $ 8.9
Penn............................................. 1.0 0.8 2.5 1.3
CEI.............................................. 3.6 3.6 9.2 6.4
TE............................................... 1.3 1.8 3.4 3.2
JCP&L............................................ 0.9 5.9 2.5 12.4
Met-Ed........................................... 0.5 3.0 1.8 6.6
Penelec.......................................... 0.4 3.0 1.8 6.5
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. The plan amendment, which increases cost-sharing by
employees and retirees effective January 1, 2005, reduced postretirement benefit
costs during the three months and six months ended June 30, 2004, by $13 million
and $22 million, respectively.
Consistent with the guidance in FSP 106-2 issued May 19, 2004,
FirstEnergy recognized a reduction of $318 million in the accumulated
postretirement benefit obligation as a result of the federal subsidy provided
under the Medicare Act related to benefits for past service. The subsidy reduced
net periodic postretirement benefit costs during the three months and six months
ended June 30, 2004, as follows:
Impact of federal subsidy provided under the Medicare Act Three Months Six Months
--------------------------------------------------------- -------------- ----------
(In millions)
Service cost .................................... $ (2) $ (3)
Interest cost.................................... (5) (10)
Recognized net actuarial loss.................... (5) (11)
------ ------
Decrease in net periodic cost.................... $ (12) $ (24)
====== ======
The impact of the subsidy was not material to the financial
statements of each of the Companies for the three and six months ended June 30,
2004.
5 - DIVESTITURES:
FirstEnergy completed the sale of its international operations 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.
FirstEnergy completed the sale of its 50% interest in GLEP on June
23, 2004. Proceeds of $220 million included cash of $200 million and the right,
valued at $20 million, to participate for up to a 40-percent interest in future
wells in Ohio. This transaction produced an after-tax loss of $7 million, or
$0.02 per share of common stock, including the benefits of prior tax capital
losses that had been previously fully reserved, which offset the capital gain
from the sale.
14
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. However, despite these
similarities, the specific approach taken by each state and for each of the
Companies varies. These provisions include:
o allowing the Companies' electric customers to select their
generation suppliers;
o establishing PLR obligations to non-shopping customers in
the Companies' service areas;
o allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
o deregulating the Companies' electric generation businesses;
o continuing regulation of the Companies' transmission and
distribution systems; and
o requiring corporate separation of regulated and unregulated
business activities.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
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, was an independent review to identify areas
recommended for reliability improvement. The final audit report was completed on
May 6, 2004. The report identified positive observations and included various
recommendations for reliability improvement. FirstEnergy implemented the audit
results and recommendations relating to summer 2004 and reported completion of
those recommendations on June 30, 2004, with one exception related to MISO's
implementation of a voltage stability tool expected to be finalized later this
year. Implementation of the recommendations has not required incremental
material investment or upgrades to existing equipment.
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 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
15
On April 22, 2004, FirstEnergy filed with the 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 2009. FirstEnergy is continuing to review
the results of that study related to 2009 and completed the implementation of
recommendations relating to 2004 by June 30, 2004. 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
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 (SRM) be hired to oversee the investigation. On
December 8, 2003, the SRM 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 and
procedures of JCP&L. The audit was expanded to include the July 2003 outage and
was completed in January 2004. On June 9, 2004, the NJBPU approved a stipulation
that incorporated the final SRM report and portions of the final Booth report.
JCP&L is awaiting the final NJBPU order.
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 required additional reporting
on reliability. The PPUC ordered all Pennsylvania utilities to begin filing
quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
approving the revised reliability benchmark and standards, including revised
benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted
Pennsylvania utilities to file in a separate proceeding to revise the recomputed
benchmarks and standards if they have evidence, such as the impact of automated
outage management systems, on the accuracy of the PPUC computed reliability
indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks
with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards
due to their implementation of automated outage management systems following
restructuring. No procedural schedule or hearing date has been set for this
proceeding. FirstEnergy is unable to predict the outcome of this proceeding.
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 was filed May 7, 2004.
On June 21, 2004, intervenors filed rebuttal testimony and Met-Ed's, Penelec's
and Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held
in early August 2004 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 the end of 2004. FirstEnergy is unable to predict the
outcome of the investigation or the impact of the PPUC order.
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
16
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 EUOC) 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.
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 EUOC's 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.
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 through an extension of the regulatory transition
charge. Under the modified Rate Stabilization Plan described below, the deferred
incentives and deferred interest costs related to the incentives will be
amortized on a dollar-for-dollar basis as the associated revenues are
recognized.
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 that proposal, the Ohio EUOC requested:
o Extension of the transition cost amortization period for OE
from 2006 to 2007; for CEI from 2008 to 2009 and for TE from
mid-2007 to 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 February 23, 2004, after consideration of the 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. On June
9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan,
subject to conducting a competitive bid process on or before December 1, 2004.
In addition to requiring the competitive bid process, the PUCO made other
modifications to FirstEnergy's revised Rate Stabilization Plan application.
Among the major modifications were the following:
o Limiting the ability of the Ohio EUOC to request adjustments
in generation charges during 2006 through 2008 for increases
in taxes;
17
o Expanding the availability of market support generation;
o Revising the kilowatt-hour target level and the time period
for recovering regulatory transition charges;
o Establishing a 3-year competitive bid process for
generation;
o Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008;
and
o Denying the ability to defer costs for future recovery of
distribution reliability improvement expenditures.
On June 18, 2004, the Ohio EUOC filed with the PUCO an application
for rehearing of the modified version of the Rate Stabilization Plan. Several
other parties also filed applications for rehearing. On August 4, 2004, the PUCO
issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications
included the following:
o Expanding the Ohio EUOC's ability to request adjustments in
generation charges during 2006 through 2008 to include
increases in the cost of fuel (including the cost of
emission allowances consumed, lime, stabilizers and other
additives and fuel disposal) using 2002 as the base year.
Any increases in fuel costs would be subject to downward
adjustments in subsequent years should fuel costs decline,
but not below the generation rate initially established in
the Rate Stabilization Plan;
o Approving the revised kilowatt-hour target level and time
period for recovery of regulatory transition costs as
presented by the Ohio EUOC in their rehearing application;
o Retaining the requirement for expanded availability of
market support generation, but adopting the Ohio EUOC's
alternative approach that conditions expanded availability
on higher pricing and eliminating the requirement to reduce
the interest deferral for certain affected rate schedules;
o Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and
o Relaxing the notice requirement for availability of enhanced
shopping credits in a number of instances.
On August 5, 2004, FirstEnergy accepted the Rate Stabilization Plan
as modified and approved by the PUCO on August 4, 2004. FirstEnergy retains the
right to withdraw the modified Rate Stabilization Plan should subsequent adverse
action be taken by the PUCO or a court. In the second quarter of 2004, the Ohio
EUOC implemented the accounting modifications contained in the PUCO's June 9,
2004 Order, which are consistent with the PUCO's August 4, 2004 Entry on
Rehearing. Those modifications included amortization of transition costs based
on extended amortization periods (that are no later than 2007 for OE, mid-2009
for CEI and mid-2008 for TE) and the deferral of interest costs on the
accumulated deferred shopping incentives.
Transition Cost Amortization
OE, CEI and TE amortize transition costs (see Regulatory Matters -
Ohio) using the effective interest method. Under the Rate Stabilization Plan as
approved above, total transition cost amortization is expected to approximate
the following for 2004 through 2009:
(In millions)
--------------------------------------
2004...................... $754
2005...................... 841
2006...................... 389
2007...................... 317
2008...................... 160
2009...................... 44
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
18
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
as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets)
which securitized the recovery of these costs and which provided for a
usage-based non-bypassable TBC to cover debt service on the bonds.
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 June 30, 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 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
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 the subsequent six to
twelve months. During that period, JCP&L would 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 charge. 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. In its final decision and
order issued on May 17, 2004, the NJPBU clarified the method for calculating
interest attributable to the cost disallowances, resulting in a $5.4 million
reduction from the amount estimated in 2003. On June 1, 2004, JCP&L filed with
the NJBPU a supplemental and amended motion for rehearing and reconsideration.
On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the
following issues: (1) deferred costs disallowances, (2) the capital structure
including the rate of return, (3) merger savings, (4) amortization of costs to
achieve merger savings; and (5) decommissioning. All other issues included in
JCP&L's amended motion were denied. Oral arguments were held on August 4, 2004.
Management cannot predict when a decision following the oral arguments may be
announced by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU
which requested an increase in base rates of $36 million, reflecting the
recovery of system reliability costs and a higher return on equity. The filing
also requests an increase to the MTC deferred balance recovery of approximately
$20 million annually. The filing fulfills the NJBPU requirement that a Phase II
proceeding be conducted and that any expenditures and projects undertaken by
JCP&L to increase its system reliability be reviewed.
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 periods beginning June 1, 2004 was completed in February
2004 and new BGS tariffs reflecting the auction results became effective June 1,
2004. On May 25, 2004, the NJBPU issued an order adopting a schedule for the BGS
post transition year three process. JCP&L filed its proposal suggesting how BGS
should be procured for year three and beyond.
19
In accordance with an April 28, 2004 NJBPU order, JCP&L filed
testimony on June 7, 2004 supporting a continuation of the current level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers
without a reduction, termination or capping of the funding.
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 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.
Met-Ed and Penelec purchase a portion of their PLR requirements from
FES through a wholesale power sale agreement. The PLR sale is 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 retains the supply obligation and the supply profit and loss
20
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.
7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:
Exposure Draft of Proposed Statement of Financial Accounting Standards -
Share-Based Payment - an amendment of FASB Statements No. 123 and 95
During March 2004, the FASB issued an exposure draft of a new
standard, which would amend SFAS 123 and SFAS 95. Among other items, the new
standard would require expensing stock options in FirstEnergy's financial
statements. The new standard, as proposed, would be effective January 1, 2005,
for calendar year companies. FirstEnergy will not be able to determine the exact
impact of the proposed standard on its results of operations until the standard
is issued in final form. The impact of the fair value recognition provisions of
SFAS 123 on FirstEnergy's net income and earnings per share for the current
reporting periods is disclosed in Note 2.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the
EITF on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. FirstEnergy has
available-for-sale securities with unrealized losses of approximately $21
million as of June 30, 2004 and other equity investments that will be evaluated
in accordance with EITF 03-1 in the third quarter of 2004. Implementation of
this guidance is not expected to have a material impact on the consolidated
financial statements of the Companies.
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 was effective for fiscal periods beginning after March 31,
2004 and had no impact on FirstEnergy's computation of earnings per share.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on accounting for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. The effect of the federal subsidy provided under the Medicare Act
on FirstEnergy's consolidated financial statements is described in Note 4. The
impact of the subsidy was not material to the financial statements of each of
the Companies for the three and six months ended June 30, 2004.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of ARB 51
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 the consolidated financial statements of FirstEnergy
or the Companies.
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"
21
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.
The competitive services business segment consists of the subsidiaries (FES,
FSG, MYR and FirstCom) that operate unregulated energy and energy-related
businesses, including the operation of FirstEnergy's generation facilities
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 segment 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. Segment results for
2003 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).
22
Segment Financial Information
- -----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
--------- ----------- ----- ----------- ------------
(In millions)
Three Months Ended:
- ------------------
June 30, 2004
-------------
External revenues..................... $ 1,289 $1,853 $ 6 $ 2 (a) $ 3,150
Internal revenues..................... -- -- 128 (128)(b) --
Total revenues..................... 1,289 1,853 134 (126) 3,150
Depreciation and amortization......... 330 9 10 -- 349
Net interest charges.................. 109 11 72 (12)(b) 180
Income taxes.......................... 175 29 (26) -- 178
Net income (loss)..................... 240 41 (77) -- 204
Total assets.......................... 29,101 2,171 738 -- 32,010
Total goodwill........................ 5,965 136 -- -- 6,101
Property additions.................... 129 60 7 -- 196
June 30, 2003
-------------
External revenues..................... $ 1,237 $1,575 $ 45 $ (4)(a) $ 2,853
Internal revenues..................... -- -- 147 (147)(b) --
Total revenues..................... 1,237 1,575 192 (151) 2,853
Depreciation and amortization......... 338 7 9 -- 354
Net interest charges.................. 132 11 104 (41)(b) 206
Income taxes.......................... 154 (105) (31) -- 18
Income before discontinued operations and
cumulative effect of accounting change 215 (152) (53) -- 10
Net income (loss)..................... 215 (152) (121) -- (58)
Total assets.......................... 30,123 2,499 1,403 -- 34,025
Total goodwill........................ 5,993 256 -- -- 6,249
Property additions.................... 92 79 29 -- 200
Six Months Ended:
- ----------------
June 30, 2004
-------------
External revenues..................... $ 2,585 $3,726 $ 12 $ 9 (a) $ 6,332
Internal revenues..................... -- -- 248 (248)(b) --
Total revenues..................... 2,585 3,726 260 (239) 6,332
Depreciation and amortization......... 724 18 20 -- 762
Net interest charges.................. 215 23 141 (27)(b) 352
Income taxes.......................... 322 29 (57) -- 294
Net income (loss)..................... 456 41 (119) -- 378
Total assets.......................... 29,101 2,171 738 -- 32,010
Total goodwill........................ 5,965 136 -- -- 6,101
Property additions.................... 220 105 10 -- 335
June 30, 2003
-------------
External revenues..................... $ 2,546 $3,449 $ 79 $ -- (a) $ 6,074
Internal revenues..................... -- -- 271 (271)(b) --
Total revenues..................... 2,546 3,449 350 (271) 6,074
Depreciation and amortization......... 699 14 18 -- 731
Net interest charges.................. 256 23 208 (76)(b) 411
Income taxes.......................... 344 (171) (60) -- 113
Income before discontinued operations and
cumulative effect of accounting change 472 (243) (104) -- 125
Net income (loss)..................... 573 (247) (165) -- 161
Total assets.......................... 30,123 2,499 1,403 -- 34,025
Total goodwill........................ 5,993 256 -- -- 6,249
Property additions.................... 210 158 56 -- 424
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.
23
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(In thousands, except per share amounts)
REVENUES:
Electric utilities..................................... $2,170,570 $2,082,659 $4,347,603 $4,399,023
Unregulated businesses................................. 979,203 770,440 1,984,744 1,674,813
---------- ---------- ---------- ----------
Total revenues..................................... 3,149,773 2,853,099 6,332,347 6,073,836
---------- ---------- ---------- ----------
EXPENSES:
Fuel and purchased power............................... 1,095,135 1,038,317 2,229,461 2,138,953
Purchased gas.......................................... 102,963 123,814 256,491 348,611
Other operating expenses............................... 882,910 939,759 1,724,525 1,866,344
Provision for depreciation and amortization............ 349,445 354,190 761,677 730,553
General taxes.......................................... 157,732 162,885 336,817 340,952
---------- ---------- ---------- ----------
Total expenses..................................... 2,588,185 2,618,965 5,308,971 5,425,413
---------- ---------- ---------- ----------
NET INTEREST CHARGES:
Interest expense....................................... 179,881 199,278 352,745 399,539
Capitalized interest................................... (5,280) (7,622) (11,750) (16,774)
Subsidiaries' preferred stock dividends................ 5,389 13,860 10,670 28,402
---------- ---------- ---------- ----------
Net interest charges............................... 179,990 205,516 351,665 411,167
---------- ---------- ---------- ----------
INCOME TAXES.............................................. 177,553 18,283 293,667 112,541
---------- ---------- ---------- ----------
INCOME BEFORE DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE................. 204,045 10,335 378,044 124,715
Discontinued operations (net of income taxes (benefit)
of ($635,000) and $2,577,000 in the 2003 three months
and six months periods, respectively) (Note 2)......... -- (68,223) -- (66,248)
Cumulative effect of accounting change (net of income
taxes of $72,516,000) (Note 2)......................... -- -- -- 102,147
---------- ---------- ---------- ----------
NET INCOME (LOSS)......................................... $ 204,045 $ (57,888) $ 378,044 $ 160,614
========== ========== ========== ==========
BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative
effect of accounting change.......................... $ 0.62 $ 0.03 $ 1.16 $ 0.43
Discontinued operations (net of income taxes) (Note 2). -- (0.23) -- (0.23)
Cumulative effect of accounting change (net of income
taxes) (Note 2)...................................... -- -- -- 0.35
------- ------ -------- --------
Net income (loss)...................................... $ 0.62 $ (0.20) $ 1.16 $ 0.55
======= ======= ======= =======
WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING............................................ 327,284 294,166 327,171 294,026
======= ======= ======= =======
DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative
effect of accounting change.......................... $ 0.62 $ 0.03 $ 1.15 $ 0.42
Discontinued operations (net of income taxes) (Note 2). -- (0.23) -- (0.23)
Cumulative effect of accounting change (net of income
taxes) (Note 2)...................................... -- -- -- 0.35
------- ------- ------- -------
Net income (loss)...................................... $ 0.62 $ (0.20) $ 1.15 $ 0.54
======= ======= ======= =======
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING............................................ 329,103 295,888 329,061 295,355
======= ======= ======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $0.375 $0.375 $ 0.75 $ 0.75
====== ====== ======= =======
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.
24
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(In thousands)
NET INCOME (LOSS)......................................... $204,045 $(57,888) $378,044 $160,614
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges............ 19,244 (6,230) 20,609 1,539
Unrealized gain (loss) on available for sale securities (19,122) 63,825 (2,193) 52,552
Currency translation adjustments....................... -- 89,790 -- 91,461
-------- -------- -------- --------
Other comprehensive income........................... 122 147,385 18,416 145,552
Income tax related to other comprehensive income....... (314) (24,058) (9,785) (23,488)
-------- -------- -------- --------
Other comprehensive income (loss), net of tax........ (192) 123,327 8,631 122,064
-------- -------- -------- --------
COMPREHENSIVE INCOME...................................... $203,853 $ 65,439 $386,675 $282,678
======== ======== ======== ========
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.
25
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................................... $ 99,538 $ 113,975
Certificates of deposit...................................................... 277,763 --
Receivables-
Customers (less accumulated provisions of $47,852,000 and $50,247,000,
respectively, for uncollectible accounts)................................ 998,954 1,000,259
Other (less accumulated provisions of $29,836,000 and $18,283,000,
respectively, for uncollectible accounts)................................ 340,120 505,241
Materials and supplies, at average cost-
Owned...................................................................... 356,142 325,303
Under consignment.......................................................... 92,251 95,719
Prepayments and other........................................................ 253,960 202,814
----------- -----------
2,418,728 2,243,311
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................................... 22,051,544 21,594,746
Less--Accumulated provision for depreciation................................. 9,352,540 9,105,303
----------- -----------
12,699,004 12,489,443
Construction work in progress................................................ 602,677 779,479
----------- -----------
13,301,681 13,268,922
----------- -----------
INVESTMENTS:
Nuclear plant decommissioning trusts......................................... 1,425,027 1,351,650
Investments in lease obligation bonds ....................................... 955,133 989,425
Certificates of deposit ..................................................... -- 277,763
Other........................................................................ 723,727 878,853
----------- -----------
3,103,887 3,497,691
----------- -----------
DEFERRED CHARGES:
Regulatory assets............................................................ 6,383,579 7,076,923
Goodwill..................................................................... 6,100,969 6,127,883
Other........................................................................ 700,756 695,218
----------- -----------
13,185,304 13,900,024
----------- -----------
$32,009,600 $32,909,948
=========== ===========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock......................... $ 1,477,780 $ 1,754,197
Short-term borrowings ....................................................... 74,436 521,540
Accounts payable............................................................. 612,894 725,239
Accrued taxes................................................................ 815,988 669,529
Other........................................................................ 762,267 801,662
----------- -----------
3,743,365 4,472,167
----------- -----------
CAPITALIZATION:
Common stockholders' equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-
329,836,276 shares outstanding........................................... 32,984 32,984
Other paid-in capital...................................................... 7,055,392 7,062,825
Accumulated other comprehensive loss....................................... (344,018) (352,649)
Retained earnings.......................................................... 1,738,643 1,604,385
Unallocated employee stock ownership plan common stock-
2,461,977 and 2,896,951 shares, respectively............................. (50,038) (58,204)
----------- -----------
Total common stockholders' equity...................................... 8,432,963 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............................... 9,915,920 9,789,066
----------- -----------
18,684,006 18,413,530
----------- -----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes............................................ 2,017,716 2,178,075
Asset retirement obligations................................................. 1,217,067 1,179,493
Power purchase contract loss liability....................................... 2,430,259 2,727,892
Retirement benefits.......................................................... 1,655,797 1,591,006
Lease market valuation liability............................................. 978,600 1,021,000
Other........................................................................ 1,282,790 1,326,785
----------- -----------
9,582,229 10,024,251
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3).............................. ----------- -----------
----------- -----------
$32,009,600 $32,909,948
=========== ===========
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these balance sheets.
26
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2004 2003 2004 2003
--------- --------- --------- -----------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 204,045 $ (57,888) $ 378,044 $ 160,614
Adjustments to reconcile net income (loss) to net cash
from operating activities-
Provision for depreciation and amortization........ 349,445 354,190 761,677 730,553
Nuclear fuel and lease amortization................ 23,132 15,578 45,006 30,496
Other amortization, net............................ (2,718) (409) (7,441) (5,022)
Deferred costs recoverable as regulatory assets.... (60,974) 37,812 (144,881) (56,499)
Deferred income taxes, net......................... (93,594) (48,576) (81,197) (20,435)
Investment tax credits, net........................ (6,462) (6,247) (12,936) (12,506)
Disallowed regulatory assets (Note 6).............. -- 152,500 -- 152,500
Cumulative effect of accounting change (Note 2).... -- -- -- (174,663)
Loss from discontinued operations (Note 2)......... -- 68,223 -- 66,248
Receivables........................................ (101,304) (58,659) 171,442 (60,557)
Materials and supplies............................. (20,617) (45,397) (27,371) (33,984)
Prepayments and other current assets............... (2,582) (50,885) (49,613) (120,558)
Accounts payable................................... 68,376 (27,928) (108,642) (35,043)
Accrued taxes...................................... 114,867 (75,699) 146,796 21,854
Accrued interest................................... (93,002) (105,669) (6,366) (16,459)
Deferred rents and sale/leaseback valuation
liability........................................ (64,287) (62,370) (80,584) (79,962)
Other.............................................. 5,925 (66,845) (14,061) (62,584)
--------- ---------- ---------- -----------
Net cash provided from operating activities...... 320,250 21,731 969,873 483,993
--------- ---------- ---------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 303,162 722,041 884,720 1,019,737
Short-term borrowings, net........................... -- 189,741 -- --
Redemptions and Repayments-
Preferred stock...................................... -- (125,337) -- (125,337)
Long-term debt....................................... (721,023) (815,166) (989,943) (1,016,032)
Short-term borrowings, net........................... (59,563) -- (447,104) (47,749)
Net controlled disbursement activity................... 25,385 19,277 (17,271) 33,721
Common stock dividend payments......................... (121,321) (110,284) (243,786) (220,443)
--------- ---------- ---------- -----------
Net cash used for financing activities........... (573,360) (119,728) (813,384) (356,103)
--------- ---------- ---------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (196,094) (199,742) (334,500) (424,161)
Nonutility generation trust withdrawals
(contributions)...................................... -- -- (50,614) 106,327
Contributions to nuclear decommissioning trusts........ (25,372) (2,988) (50,742) (28,251)
Proceeds from asset sales.............................. 200,008 5,877 211,447 66,449
Proceeds from note receivable.......................... -- 19,000 -- 19,000
Cash investments....................................... 6,738 (9,650) 26,956 15,065
Other.................................................. 87,099 78,945 26,527 19,305
--------- ---------- ---------- -----------
Net cash provided from (used for)
investing activities........................... 72,379 (108,558) (170,926) (226,266)
--------- ---------- ---------- -----------
Net decrease in cash and cash equivalents................. (180,731) (206,555) (14,437) (98,376)
Cash and cash equivalents at beginning of period.......... 280,269 334,111 113,975 225,932
--------- ---------- ---------- -----------
Cash and cash equivalents at end of period................ $ 99,538 $ 127,556 $ 99,538 $ 127,556
========= ========== ========== ===========
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.
27
99
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related consolidated
statements of income, comprehensive income and cash flows for each of the
three-month and six-month periods ended June 30, 2004 and 2003. These interim
financial statements are the responsibility of the Company's management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 the standards of the Public Company
Accounting Oversight Board (United States), 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 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
August 6, 2004
28
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE SUMMARY
Net income in the second quarter of 2004 was $204 million, or basic
and diluted earnings of $0.62 per share of common stock, compared to a net loss
of $58 million, or $0.20 per share of common stock for the second quarter of
2003. FirstEnergy's second quarter earnings reflect solid progress -
particularly in the areas of sales from its regulated segment and performance of
its generation portfolio. Net income in the first half of 2004 was $378 million,
or $1.16 per share of common stock ($1.15 diluted), compared to $161 million, or
$0.55 per share of common stock ($0.54 diluted) for the first six months of
2003. Earnings in the second quarter and first six months of 2004 were reduced
on a per share basis from the issuance and sale of 32.2 million shares of common
stock in the third quarter of 2003. The additional shares reduced earnings per
share of common stock (basic and diluted) by $0.07 and $0.13, respectively.
Higher sales in the second quarter of 2004, compared with the
year-earlier quarter, were related to a stronger economy and warmer weather.
Revenues were offset slightly by lower prices that resulted from a reduction in
JCP&L base rates and higher customer shopping levels to alternate suppliers in
FirstEnergy's Ohio service area. Sales from FirstEnergy's regulated utility
companies remain the largest source of revenues, contributing more than 60% of
total revenues.
The restart of the Davis-Besse Nuclear Power Station, which began
operating at full power on April 4, 2004, and improved performance of the
generation fleet, continue to have a positive impact on earnings. Reorganization
of FENOC is expected to further increase operating efficiency at FirstEnergy's
three nuclear plants by standardizing structure and processes.
FirstEnergy's pension and other postemployment benefits expense
decreased by $22 million in the second quarter of 2004, compared to the same
period last year, due to higher trust asset values, revisions to its health care
benefits plan, and the positive impact of the new Medicare Act, enacted in
December 2003. The same factors contributed to a $48 million decrease in the
first half of 2004, compared to the first half of 2003.
FirstEnergy further strengthened its financial position during the
second quarter of 2004 by divesting its 50% interest in GLEP, generating
after-tax net proceeds of $150 million that were used to reduce debt. This sale
is consistent with FirstEnergy's strategy to divest non-core assets and focus on
its core electric business. In addition to that, FirstEnergy has substantially
completed divestiture of all international operations - acquired as part of its
merger with the former GPU - and sold three HVAC companies in the past 18
months.
FirstEnergy's debt paydown program resulted in a decrease of
approximately $600 million in total debt during the first half of 2004.
FirstEnergy remains on track to achieve its goal of reducing debt by at least $1
billion this year. FirstEnergy also improved its financial flexibility with the
replacement of $1 billion of its credit commitments that, combined with other
existing credit facilities, brings the total capacity of FirstEnergy's primary
credit facilities and those of its subsidiaries to $2.3 billion.
On July 23, 2004, FirstEnergy announced that Richard R. Grigg was
elected Executive Vice President and Chief Operating Officer. Mr. Grigg retired
earlier this year as President and Chief Executive Officer of WE Generation,
after nearly 34 years with Wisconsin Energy Corporation. He will join
FirstEnergy in the third quarter of 2004 and will lead several operating
business units including Energy Delivery, Fossil Generation and Commodity
Operations.
On June 18, 2004, FirstEnergy filed a request for rehearing of
portions of its Ohio Rate Stabilization Plan, which the PUCO approved with
modifications on June 9, 2004. On August 5, 2004, FirstEnergy accepted the Rate
Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In
addition to providing enhanced customer benefits, the approved plan adequately
addressed most of the issues raised by FirstEnergy. These included the ability
to seek recovery of increased fuel costs and terms for offering market support
generation. In the second quarter of 2004, FirstEnergy implemented the
accounting modifications approved by the PUCO in the Rate Stabilization Plan
order.
On July 27, 2004, FirstEnergy announced that it had reached an
agreement to resolve various pending legal proceedings filed against FirstEnergy
and certain of its officers and directors, alleging violations of federal
securities laws and related state laws (see Outlook - Other Legal Matters below)
in connection with financial restatements of previously reported results in
August 2003, the regional power outage on August 14, 2003, and the extended
outage at the Davis-Besse Nuclear Power Station. The settlement agreement, which
29
does not constitute an admission of wrongdoing, provides for a total settlement
payment of $89.9 million, of which FirstEnergy's insurance carrier will pay
$71.92 million. FirstEnergy will pay $17.98 million, resulting in an after-tax
charge against FirstEnergy's second quarter and year-to-date 2004 earnings of
$11 million or $0.03 per common share (basic and diluted). The settlement is
subject to court approval and, although not anticipated to occur, in the event
that a significant number of shareholders do not accept the terms of the
settlement, the Company and individual defendants have the right, but not the
obligation, to set aside the settlement and recommence the litigation.
FirstEnergy is participating in meaningful settlement negotiations
with the parties to the New Source Review case involving its W. H. Sammis Plant
(see Outlook - Environmental Matters). As a result, the U.S. District Court
judge hearing the case has rescheduled the date for the remedy phase of the
trial to January 2005.
FirstEnergy continues to make investments designed to enhance
customer service reliability. Installation of new computer equipment for its
system control centers in Ohio and Pennsylvania was completed in the second
quarter of 2004 and control room operator training and procedures were
strengthened. An enhanced vegetation management program includes foot patrols
and more comprehensive aerial patrols of FirstEnergy's high-voltage transmission
system. Recently, FirstEnergy received verification from the NERC of its
completion of the various items related to NERC's readiness audit and
reliability recommendations, as well as the U.S. - Canada Task Force findings.
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, MYR and
FirstEnergy's majority owned FirstCom. Services provided through these
subsidiaries include heating, ventilation, air-conditioning, refrigeration,
process piping, plumbing, electrical and facility control systems and
high-efficiency electrotechnologies. Telecommunication services such as local
and long-distance phone service are also 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 Ohio Rate Stabilization Plan, the deadline for achieving structural
separation by transferring the ownership of applicable EUOC generating assets to
FGCO was extended until twelve months after the termination of the Rate
Stabilization Plan, unless otherwise extended further by the PUCO, or until
December 31, 2008, whichever is earlier. 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 its 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 had been divested (see Note 5)
- - supporting FirstEnergy's commitment to focus on its core electric business.
FirstEnergy's current focus includes: (1) continuing safe operations;
(2) enhancing customer service; (3) optimizing its generation portfolio; (4)
minimizing unplanned extended generation outages; (5) effectively managing
commodity supplies and risks; (6) reducing its cost structure; (7) enhancing its
credit profile and financial flexibility; and (8) managing the skills and
diversity of its workforce.
30
Reclassifications
As further discussed in Notes 1 and 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 results in 2003. 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.
RESULTS OF OPERATIONS
The increase in net income of $262 million in the second quarter and
$217 million in the first six months of 2004 includes an increase in income from
continuing operations of $194 million and $253 million, respectively, when
current period results are compared to those of 2003. A significant portion of
the improvement between periods resulted from a charge of $159 million included
in the second quarter of 2003 for costs disallowed in the JCP&L rate case
decision of July 2003. The remaining difference in the second quarter earnings
is attributable to an after-tax charge of $67 million or $0.23 per share of
common stock (basic and diluted) in the second quarter of 2003 resulting from
the abandonment of FirstEnergy's shares in Emdersa's parent company, GPU
Argentina Holdings, Inc. Results in the first six months of 2003 also included
an after-tax credit of $102 million resulting from the cumulative effect of an
accounting change due to the adoption of SFAS 143.
The results for the three and six months ended June 30, 2004 and 2003
are summarized in the table below.
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- -------------------
FirstEnergy 2004 2003 2004 2003
--------------------------------------------------------------------------------------------------
(In millions)
Total revenues............................. $3,150 $2,853 $6,332 $6,074
Income before discontinued operations
and cumulative effect of accounting change 204 10 378 125
Discontinued operations.................... -- (68) -- (66)
Cumulative effect of accounting change..... -- -- -- 102
---------------------------------------------------------------------------------------------------
Net Income (Loss).......................... $ 204 $ (58) $ 378 $ 161
===================================================================================================
Basic Earnings Per Share:
Income before discontinued operations and
cumulative effect of accounting change $0.62 $ 0.03 $1.16 $ 0.43
Discontinued operations................. -- (0.23) -- (0.23)
Cumulative effect of accounting change.. -- -- -- 0.35
----------------------------------------------------------------------------------------------------
Net Income (Loss).......................... $0.62 $(0.20) $1.16 $ 0.55
====================================================================================================
Diluted Earnings Per Share:
Income before discontinued operations and
cumulative effect of accounting change $0.62 $ 0.03 $1.15 $ 0.42
Discontinued operations................. -- (0.23) -- (0.23)
Cumulative effect of accounting change.. -- -- -- 0.35
----------------------------------------------------------------------------------------------------
Net Income (Loss).......................... $0.62 $(0.20) $1.15 $ 0.54
====================================================================================================
Results of Operations - Second Quarter of 2004 Compared With the Second
Quarter of 2003
Total revenues increased $297 million in the second quarter of 2004.
The sources of changes in total revenues are summarized in the following table:
31
Three Months Ended
June 30,
--------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Retail Electric Sales:
EUOC - Wires..................... $1,133 $1,145 $ (12)
- Generation......... 757 726 31
FES.............................. 164 122 42
Wholesale Electric Sales:
EUOC............................. 127 129 (2)
FES.............................. 463 251 212
- ------------------------------------------------------------------------------
Total Electric Sales............... 2,644 2,373 271
- ------------------------------------------------------------------------------
Transmission Revenues.............. 89 17 72
Gas Sales.......................... 114 130 (16)
Other Revenues:
Regulated services................ 64 65 (1)
Competitive services.............. 232 233 (1)
International..................... -- 7 (7)
Miscellaneous..................... 7 28 (21)
- --------------------------------------------------------------------------------
Total Revenues..................... $3,150 $2,853 $ 297
================================================================================
Changes in electric generation kilowatt-hour sales and distribution
deliveries in the second quarter of 2004 are summarized in the following table:
Increase
Changes in KWH Sales (Decrease)
------------------------------------------------------
Electric Generation Sales:
Retail -
EUOC.................................. (0.7)%
FES................................... 12.5 %
Wholesale............................... 37.0 %
------------------------------------------------------
Total Electric Generation Sales.......... 12.0 %
======================================================
EUOC Distribution Deliveries:
Residential............................. 6.4%
Commercial.............................. 5.2%
Industrial.............................. 1.2%
------------------------------------------------------
Total Distribution Deliveries............ 4.0%
======================================================
Retail sales by FirstEnergy's EUOC remain the largest source of
revenues, contributing more than 70% of electric revenues and over 60% of total
revenues. The following major factors contributed to the $19 million increase in
retail electric revenues from FirstEnergy's EUOC in the second quarter of 2004.
Sources of the Changes in EUOC Retail Electric Revenue
------------------------------------------------------
Increase (Decrease) (In millions)
Changes in Customer Consumption:
Alternative suppliers.................. $(22)
Economic, weather and other............ 64
----------------------------------------------------
42
Changes in Price:
Rate changes........................... (10)
Shopping incentives.................... (19)
Rate mix and other..................... 6
----------------------------------------------------
(23)
----------------------------------------------------
Net Increase............................. $ 19
====================================================
Increased customer usage offset in part by lower rates contributed to
higher EUOC retail electric revenues. A stronger economy and warmer weather in
the second quarter of 2004 compared to the same quarter of 2003 combined to more
than offset the effect of reduced usage due to alternative energy suppliers
providing a larger portion of franchise customer energy requirements.
Alternative suppliers provided 25.0% of the total energy delivered to retail
customers in the second quarter of 2004, compared to 21.4% in the same period of
2003. Overall, generation sales added $31 million to the increase in EUOC
revenues. While distribution throughput increased in the second quarter of 2004
compared to the same period last year, distribution revenues decreased,
reflecting lower rates. On July 25, 2003, the NJBPU announced its JCP&L base
electric rate proceeding decision (see Outlook - State Regulatory Matters - New
Jersey), which reduced JCP&L's base distribution rates effective August 1, 2003
and lowered revenues in the second quarter of 2004. Incentives to encourage
customer shopping contributed another $19 million to the decrease.
32
Electric sales by FES increased by $254 million primarily from
additional spot sales to the wholesale market which increased $212 million in
the second quarter of 2004. Higher electric sales to the wholesale market
resulted in part from nuclear generation more than doubling its output,
primarily as a result of the Davis-Besse restart and fewer outages, which
increased total available internal generation by 22%. Competitive retail sales
increased by $42 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 June 30, 2004 and 2003 are summarized as
follows:
Three Months Ended
June 30,
--------------------------
2004 2003 (1)
-----------------------------------------------------------
(In millions)
Sales......................... $382 $201
Purchases..................... 319 217
-------------------------------------------------------
(1) Certain prior year energy sales and purchases amounts have been
reclassified to transmission revenues and expenses (see Note 8).
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
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.
Transmission revenues increased $72 million ($16 million net of
related expenses), primarily reflecting transactions with MISO, which began
operations in December 2003 through the pooling of transmission capacity of
Midwestern utilities to provide unbundled, regional transmission services for
electric utilities.
Natural gas sales were $15 million lower (excluding the GLEP
partnership interest) primarily due to the expiration of FES customer choice
contracts and reduced sales to the wholesale market. Lower than anticipated
margins and higher administrative costs resulted in FES exiting customer choice
markets as contracts expired. FES scaled back its participation in the natural
gas wholesale market due to increasing volatility and risk associated with that
business. Increased sales to large commercial and industrial customers in the
second quarter of 2004 reflected higher prices - partially offset by declines in
sales to the customer choice and wholesale markets.
The generation margin in the second quarter of 2004 improved by $226
million compared to the same period in 2003. A major portion of the improvement
resulted from the effect of $153 million of purchased power costs disallowed in
the JCP&L rate case decision of 2003 that were expensed in the second quarter of
that year. Excluding the impact of the JCP&L decision, the generation margin
increased $73 million, benefiting from additional lower-cost nuclear generation.
Higher electric generation sales resulted principally from the additional sales
to the wholesale market. The gas margin increased $6 million despite lower
overall sales volumes due to better unit margins on increased sales to
commercial and industrial customers using low cost supply previously dedicated
to the customer choice contracts.
Three Months Ended
June 30,
----------------------- Increase
Energy Revenue Net of Commodity Costs 2004 2003 (Decrease)
----------------------------------------------------------------------------------------------------
(In millions)
Electric generation revenue............................ $1,512 $1,229 $283
Fuel and purchased power............................... 1,095 1,038 57
--------------------------------------------------------------------------------------------------
Generation Margin...................................... 417 191 226
--------------------------------------------------------------------------------------------------
Gas revenue(1)......................................... 109 124 (15)
Purchased gas.......................................... 103 124 (21)
--------------------------------------------------------------------------------------------------
Gas Margin............................................. 6 -- 6
--------------------------------------------------------------------------------------------------
Total Commodity Margins................................ $ 423 $ 191 $232
==================================================================================================
(1) Excludes GLEP partnership interest.
Income before income taxes, discontinued operations and cumulative
effect of an accounting change increased $353 million in the second quarter of
2004. In addition to the impact of improved electric and gas margins discussed
above, the following factors contributed to the increase in income before taxes:
33
o Lower nuclear production costs of $78 million primarily as a
result of no nuclear refueling outages in the second quarter
of 2004 compared to refueling outages at Beaver Valley Unit
1 ($15 million) and the Perry Plant ($41 million) during
last year's second quarter, and reduced incremental
maintenance costs at the Davis-Besse Plant ($19 million)
related to its restart;
o A net $25 million decrease in employee benefits expenses
primarily as a result of reduced postretirement benefit plan
expenses (see Postretirement Plans below); and
o Lower interest expense of $26 million due to debt and
preferred stock redemptions and refinancing activities and
other financing activities.
Discontinued Operations
Net income in the second quarter of 2003 included after-tax losses
from discontinued operations of $68 million reflecting the reclassification of
revenues and expenses associated with divestitures of FirstEnergy's Argentina
and Bolivia businesses, FSG subsidiaries (Colonial Mechanical, Webb Technologies
and Ancoma, Inc.) and NEO.
Postretirement Plans
Strengthened equity markets, amendments to FirstEnergy's health care
benefits plan in the first quarter of 2004 and the Medicare Act signed by
President Bush in December 2003 combined to reduce pension and other
postemployment benefits costs. Combined, these employee benefit expenses
decreased by $22 million in the second quarter of 2004. The following table
summarizes the net pension and OPEB expense for the three months ended June 30,
2004 and 2003.
Three Months Ended
Postretirement Benefits Expense(1) June 30,
------------------------------------------------------
2004 2003
---- ----
(In millions)
Pension...................... $22 $27
OPEB......................... 21 38
-----------------------------------------------------
Total...................... $43 $65
=====================================================
(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 benefits expenses.
Results of Operations - First Six Months of 2004 Compared With the
First Six Months of 2003
Total revenues increased $258 million in the first six months of
2004. The sources of changes in total revenues are summarized in the following
table:
Six Months Ended
June 30,
--------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Retail Electric Sales:
EUOC - Wires..................... $2,296 $2,359 $ (63)
- Generation 1,512 1,511 1
FES.............................. 335 242 93
Wholesale Electric Sales:
EUOC............................. 250 342 (92)
FES.............................. 907 543 364
- ----------------------------------------------------------------------------
Total Electric Sales............... 5,300 4,997 303
- ----------------------------------------------------------------------------
Transmission Revenues.............. 167 30 137
Gas Sales.......................... 278 374 (96)
Other Revenues:
Regulated services............... 122 157 (35)
Competitive services............. 452 435 17
International.................... -- 15 (15)
Miscellaneous.................... 13 66 (53)
- -------------------------------------------------------------------------------
Total Revenues..................... $6,332 $6,074 $258
===============================================================================
34
Changes in electric generation kilowatt-hour sales and distribution
deliveries in the first six months of 2004 are summarized in the following
table:
Increase
Changes in KWH Sales (Decrease)
------------------------------------------------------
Electric Generation Sales:
Retail -
EUOC................................ (3.7)%
FES................................. 18.3 %
Wholesale.............................. 28.0 %
------------------------------------------------------
Total Electric Generation Sales.......... 7.8 %
======================================================
EUOC Distribution Deliveries:
Residential............................ 2.6%
Commercial............................. 2.6%
Industrial............................. 1.0%
------------------------------------------------------
Total Distribution Deliveries............ 2.0%
======================================================
Retail sales by FirstEnergy's EUOC remain the largest source of
revenues, contributing more than 70% of electric revenues and over 60% of total
revenues. The following major factors contributed to the $62 million reduction
in retail electric revenues from FirstEnergy's EUOC in the first six months of
2004.
Sources of the Changes in EUOC Retail Electric Revenue
------------------------------------------------------
Increase (Decrease) (In millions)
Changes in Customer Consumption:
Alternative suppliers.................. $(78)
Economic, weather and other............ 67
----------------------------------------------------
(11)
----------------------------------------------------
Changes in Price:
Rate changes........................... (42)
Shopping incentives.................... (26)
Rate mix and other..................... 17
----------------------------------------------------
(51)
----------------------------------------------------
Net Decrease............................. $(62)
====================================================
Reductions in both customer usage 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 usage. Alternative suppliers provided 24.5% of the total energy
delivered to retail customers in the first six months of 2004, compared to 20.1%
in the same period of 2003. A stronger economy and warmer weather in the second
quarter of 2004 compared to the same quarter of 2003 combined to substantially
offset the effect of reduced usage due to alternative energy suppliers providing
a larger portion of franchise customer energy requirements. While distribution
throughput increased 2%, distribution revenues decreased - reflecting lower
rates. 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
base distribution rates effective August 1, 2003. The lower rates reduced
revenues by $42 million in the first six months of 2004. EUOC sales to wholesale
customers decreased by $92 million on a 31% reduction in kilowatt-hour sales -
JCP&L's sales represented substantially all of the decrease.
Electric sales by FES increased by $457 million primarily from
additional spot sales to the wholesale market which increased $364 million for
the first six months of 2004. Higher electric sales to the wholesale market
resulted from a 16% increase in internal generation available from FirstEnergy's
nuclear (50% increase) and fossil (2% increase) generating plants. Retail sales
increased by $93 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 six months ended June 30, 2004 and 2003 are summarized as
follows:
35
Six Months Ended
June 30,
--------------------------
2004 2003 (1)
-----------------------------------------------------------
(In millions)
Sales......................... $748 $445
Purchases..................... 649 564
------------------------------------------------------
(1) Certain prior year energy sales and purchases amounts have been
reclassified to transmission revenues and expenses (see Note 8).
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
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.
Transmission revenues increased $137 million ($37 million net of
related expenses), primarily reflecting transactions with MISO, which began
operations in December 2003 through the pooling of transmission capacity of
Midwestern utilities to provide unbundled regional transmission services for
electric utilities.
Natural gas sales decreased $96 million primarily due to the
expiration of FES customer choice contracts and reduced sales to the wholesale
market. Lower than anticipated margins and higher administrative costs resulted
in FES exiting customer choice markets as contracts expired. FES scaled back its
participation in the natural gas wholesale market due to increasing volatility
and risk associated with that business. Lower sales to large commercial and
industrial customers in the first half of 2004, compared to the same period in
2003 primarily reflected fewer customers.
The generation margin in the first six months of 2004 improved by
$276 million compared to the same period in 2003 as electric generation revenues
increased faster than the related costs for fuel and purchased power. Excluding
the impact of the July 2003 JCP&L rate decision discussed above, generation
margin increased $123 million and the ratio of generation margin to revenue
improved from 24.7% to 25.8% benefiting from additional lower-cost nuclear
generation. Higher electric generation sales resulted principally from the
additional sales to the wholesale market. The gas margin decreased $3 million on
reduced sales.
Six Months Ended
June 30,
---------------------- Increase
Energy Revenue Net of Commodity Costs 2004 2003 (Decrease)
----------------------------------------------------------------------------------------------------
(In millions)
Electric generation revenue............................ $3,005 $2,639 $366
Fuel and purchased power............................... 2,229 2,139 90
--------------------------------------------------------------------------------------------------
Generation Margin...................................... 776 500 276
--------------------------------------------------------------------------------------------------
Gas revenue(1)......................................... 266 362 (96)
Purchased gas.......................................... 256 349 (93)
--------------------------------------------------------------------------------------------------
Gas Margin............................................. 10 13 (3)
--------------------------------------------------------------------------------------------------
Total Commodity Margins................................ $ 786 $ 513 $273
==================================================================================================
(1) Excludes GLEP partnership interest.
Income before income taxes, discontinued operations and cumulative
effect of an accounting change increased $434 million in the first six months of
2004. In addition to the impact of improved electric and gas margins discussed
above, the following factors contributed to the increase in income before taxes:
o Lower nuclear production costs of $150 million primarily as
a result of no nuclear refueling outages in the first six
months of 2004 compared to refueling outages at Beaver
Valley Unit 1 ($47 million) and the Perry Plant ($41
million) during the same period last year and reduced
incremental maintenance costs at the Davis-Besse Plant ($54
million) related to its restart;
o A net $44 million decrease in employee benefits expenses
primarily as a result of reduced postretirement benefit plan
expenses (see Postretirement Plans below); and
o Lower interest expense of $60 million due to debt and
preferred stock redemptions and refinancing activities.
36
Partially offsetting the above sources of improved earnings were two
factors:
o Reduced revenues of $63 million from distribution deliveries
(primarily due to reduced rates); and
o Charges for depreciation and amortization that increased by
$31 million due to an increase in amortization of regulatory
assets offset in part by reduced depreciation rates
resulting from the JCP&L rate case. The increase in
regulatory asset amortization was primarily due to increased
amortization of the Ohio transition plan regulatory assets
net of deferrals and increased stranded cost amortization at
JCP&L, Met-Ed and Penelec.
Discontinued Operations
Net income in the first six months of 2003 included after-tax losses
from discontinued operations of $66 million reflecting the reclassification of
revenues and expenses associated with divestitures of FirstEnergy's Argentina
and Bolivia businesses, FSG subsidiaries (Colonial Mechanical, Webb Technologies
and Ancoma, Inc) and NEO.
Cumulative Effect of Accounting Change
Results in the first six months 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
Strengthened equity markets in 2003, amendments to FirstEnergy's
health care benefits plan in the first quarter of 2004 and the Medicare Act
signed by President Bush in December 2003 combined to reduce pension and other
postemployment benefits costs. Combined, these employee benefit expenses
decreased by $48 million in the first six months of 2004. The following table
summarizes the net pension and OPEB expense for the six months ended June 30,
2004 and 2003.
Six Months Ended
Postretirement Benefits Expense(1) June 30,
------------------------------------------------------
2004 2003
---- ----
(In millions)
Pension...................... $43 $ 59
OPEB......................... 47 79
------------------------------------------------------
Total...................... $90 $138
======================================================
(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 benefits 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. That segment's revenues include all
generation electric sales revenues (including the generation services to
regulated franchise customers who have not chosen an alternative generation
37
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, ventilation 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
delivery of electricity including transmission and
distribution 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 and FirstCom) that operate
unregulated energy and energy-related businesses, including
the operation of FirstEnergy's generation facilities as a
result of 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 Six Months Ended
Net Income (Loss) June 30, June 30,
-------------------------------------------------
By Business Segment 2004 2003 2004 2003
- --------------------------------------------------------------------------------
(In millions)
Regulated services......... $240 $ 215 $ 456 $ 573
Competitive services....... 41 (152) 41 (247)
Other(1)................... (77) (121) (119) (165)
- --------------------------------------------------------------------------------
Total...................... $204 $ (58) $ 378 $ 161
================================================================================
(1) Includes international operations and reflects an after-tax charge of
$67 million in the second quarter of 2003 related to the abandonment
of FirstEnergy's Argentina business operations.
Regulated Services - Second Quarter of 2004 Compared with the Second
Quarter of 2003
Financial results for the regulated services segment were as follows:
Three Months Ended
June 30,
------------------ Increase
Regulated Services 2004 2003 (Decrease)
- ------------------------------------------------------------------------------
(In millions)
Total revenues............................... $1,289 $1,237 $52
Income before cumulative effect of accounting
changes.................................... 240 215 25
Net Income.................................... 240 215 25
- ------------------------------------------------------------------------------
The change in operating revenues resulted from the following sources:
Three Months Ended
June 30,
--------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
---------------------------------------------------------------------
(In millions)
Electric sales............. $1,133 $1,145 $(12)
Other sales................ 156 92 64
-------------------------------------------------------------------
Total Sales................ $1,289 $1,237 $ 52
===================================================================
The increase in operating revenues resulted from:
o A net decrease of $12 million in retail sales - a $2 million
reduction in revenues from distribution deliveries (wires
and transition revenue) and a $10 million increase in the
credits for shopping incentives to customers; and
o A net $64 million increase in other sales due to higher
transmission revenues.
Increased transmission revenues contributed $16 million net of
expenses to the $25 million increase in income before cumulative effect of an
accounting change.
38
Competitive Services - Second Quarter of 2004 Compared with the
Second Quarter of 2003
Financial results for the competitive services segment were as
follows:
Three Months Ended
June 30,
--------------- Increase
Competitive Services 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Total revenues................................... $1,853 $1,575 $278
Income (Loss) before discontinued operations and
cumulative effect of accounting changes....... 41 (152) 193
Net income (loss)................................ 41 (152) 193
- --------------------------------------------------------------------------------
The change in total revenues resulted from the following sources:
Three Months Ended
June 30,
------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
-----------------------------------------------------------------------
(In millions)
Electric sales................. $1,512 $1,229 $283
Natural gas sales.............. 114 130 (16)
Energy-related sales........... 176 200 (24)
Other.......................... 51 16 35
---------------------------------------------------------------------
Total Revenues................. $1,853 $1,575 $278
=====================================================================
The increase in electric revenues resulted from:
o Higher retail generation sales through customer choice
programs ($42 million) and increased generation sales to the
EUOC ($31 million); and
o Increased FES wholesale revenues of $212 million (primarily
into the spot market) offset in part by a $2 million
decrease in EUOC sales to wholesale customers.
Natural gas sales were $16 million lower primarily due to the
expiration of FES customer choice contracts and reduced sales to the wholesale
market. Lower than anticipated margins and higher administrative costs resulted
in FES exiting customer choice markets as contracts expired. FES scaled back its
participation in the wholesale market due to increasing volatility and risk
associated with that business. Increased sales to large commercial and
industrial customers in the second quarter of 2004 - partially offset declines
in sales to the customer choice and wholesale markets. Increased sales revenues
also reflected higher prices.
The generation margin increased $226 million as the electric
generation revenues increase exceeded the increase in related costs for fuel and
purchased power. Higher electric generation revenues resulted from additional
sales to the wholesale market which benefited from increased nuclear generation.
A major portion of the improvement resulted from the effect of $153 million of
purchased power costs disallowed in the JCP&L rate case decision of July 2003
that were expensed in the second quarter of that year. Excluding the impact of
the JCP&L decision, the generation margin increased $73 million benefiting from
additional lower-cost nuclear generation. The margin on gas sales increased $6
million despite lower overall sales volumes due to better unit margins on
increased sales to commercial and industrial customers using low cost supply
previously dedicated to the customer choice contracts.
Income before discontinued operations and cumulative effect of
accounting change increased $193 million in the second quarter of 2004 and
pre-tax income increased by $327 million. In addition to the effect of improved
electric and gas margins discussed above, the following factors contributed to
the increase in pre-tax income:
o Lower nuclear production costs of $78 million primarily as a
result of no nuclear refueling outages in the second quarter
of 2004 compared to refueling outages at Beaver Valley Unit
1 ($15 million) and the Perry Plant ($41 million) during
last year's second quarter, and reduced incremental
maintenance costs at the Davis-Besse Plant ($19 million)
related to its restart; and
o Reduced employee benefits expenses primarily as a result of
lower postretirement benefit plan expenses (see
Postretirement Plans above).
39
Regulated Services - First Six Months of 2004 Compared with the First
Six Months of 2003
Financial results for the regulated services segment were as follows:
Six Months Ended
June 30,
---------------- Increase
Regulated Services 2004 2003 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Total revenues............................... $2,585 $2,546 $ 39
Income before cumulative effect of accounting
change..................................... 456 472 (16)
Net Income.................................... 456 573 (117)
- --------------------------------------------------------------------------------
The change in operating revenues resulted from the following sources:
Six Months Ended
June 30,
--------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
-----------------------------------------------------------------------
(In millions)
Electric sales............. $2,296 $2,359 $ (63)
Other revenues............. 289 187 102
-------------------------------------------------------------------
Total Revenues............. $2,585 $2,546 $ 39
===================================================================
The increase in operating revenues resulted from:
o A net decrease of $63 million in retail sales - a $57
million decrease in revenues from distribution deliveries
and a $6 million increase in shopping incentive credits to
customers; and
o A net $102 million increase in other revenues primarily due
to higher transmission revenues.
Increased expenses resulted in a $16 million decrease in income
before cumulative effect of an accounting change. Higher expenses included a $96
million increase in operating expenses from additional transmission expenses,
energy delivery costs for vegetation management and JCP&L's accelerated
reliability program, as well as increased depreciation and amortization charges
of $26 million.
Competitive Services - First Six Months of 2004 Compared with the First
Six Months of 2003
Financial results for the competitive services segment were as
follows:
Six Months Ended
June 30,
--------------- Increase
Competitive Services 2004 2003 (Decrease)
------------------------------------------------------------------------------
(In millions)
Total revenues................................... $3,726 $3,449 $277
Income (Loss) before discontinued operations and
cumulative effect of accounting changes....... 41 (243) 284
Net income (loss)................................ 41 (247) 288
------------------------------------------------------------------------------
The change in total revenues resulted from the following sources:
Six Months Ended
June 30
------------------- Increase
Sources of Revenue Changes 2004 2003 (Decrease)
-----------------------------------------------------------------------
(In millions)
Electric sales................. $3,005 $2,639 $366
Natural gas sales.............. 278 374 (96)
Energy-related sales........... 354 387 (33)
Other.......................... 89 49 40
---------------------------------------------------------------------
Total Revenues................. $3,726 $3,449 $277
=====================================================================
The increase in electric revenues resulted from:
o Higher retail generation sales from customer choice programs
($93 million) and an increase in generation sales to the
EUOC ($1 million); and
40
o Increased wholesale revenues of $364 million from FES
(primarily into the spot market) offset in part by a $92
million decrease in EUOC sales to wholesale customers.
Natural gas sales decreased $96 million primarily due to the
expiration of FES customer choice contracts and reduced sales to the wholesale
market. Lower than anticipated margins and higher administrative costs resulted
in FES exiting customer choice markets as contracts expired. Due to increased
volatility and perceived risk, FES reduced its participation in the wholesale
market. Decreased sales to large commercial and industrial customers in the
first half of 2004 primarily reflected fewer customers.
The generation margin increased $276 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. Excluding the impact of the July 2003 JCP&L rate decision, as
discussed above, the generation margin increased $123 million. The margin on gas
sales decreased $3 million on reduced sales.
Income before discontinued operations and cumulative effect of an
accounting change increased $284 million in the first six months of 2004. In
addition to the effect of improved generation and gas margins discussed above,
the following factors contributed to that increase:
o Lower nuclear production costs of $150 million primarily as
a result of no nuclear refueling outages in the first six
months of 2004 compared to refueling outages at Beaver
Valley Unit 1 ($47 million) and the Perry Plant ($41
million) during the same period last year and reduced
incremental maintenance costs at the Davis-Besse Plant ($54
million) related to its restart; and
o Reduced employee benefits expenses primarily as a result of
lower postretirement benefit plan expenses (see
Postretirement Plans above).
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 $1.375 billion of revolving credit facilities. In the first six months
of 2004, FirstEnergy received $391 million of cash dividends from its
subsidiaries and paid $244 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 June 30, 2004, FirstEnergy had
$100 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 in the second quarter and first six months of 2004,
compared with the corresponding periods of 2003 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ------------------
Operating Cash Flows 2004 2003 2004 2003
------------------------------------------------------------------------------
(In millions)
Cash earnings (1) $380 $ 381 $889 $ 744
Working capital and other (60) (359) 81 (260)
------------------------------------------------------------------------------
Total $320 $ 22 $970 $ 484
==============================================================================
(1) Includes net income, depreciation and amortization, deferred
income taxes, investment tax credits and major noncash charges.
41
Net cash provided from operating activities increased $298 million in
the second quarter of 2004 compared to the same period last year due to changes
in working capital. The working capital change resulted primarily from increases
in accounts payable and accrued taxes. During the first six months of 2004, net
cash provided from operating activities increased $486 million due to a $341
million increase from changes in working capital and $145 million of higher cash
earnings, reflecting improving generation margins. The working capital change
primarily resulted from a $232 million increase in receivables (including the
net proceeds from the settlement of FirstEnergy's claim against NRG, Inc. for
the terminated sale of four power plants) and a $125 million increase in accrued
taxes, partially offset by a $74 million decrease in accounts payable.
Cash Flows From Financing Activities
The following table provides details regarding security issuances and
redemptions during the second quarter and first six months of 2004 and 2003:
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
Securities Issued or Redeemed 2004 2003 2004 2003
- -----------------------------------------------------------------------------
(In millions)
New Issues
Pollution control notes........ $ -- $ -- $ 185 $ --
Senior secured notes........... 300 159 550 409
Unsecured notes................ 3 333 150 331
Long-term revolving credit..... -- 230 -- 280
- -----------------------------------------------------------------------------
$303 $722 $ 885 $1,020
Redemptions
First mortgage bonds........... $290 $593 $ 382 $ 633
Pollution control notes........ -- -- -- 50
Senior secured notes........... 31 222 73 333
Long-term revolving credit..... 175 -- 310 --
Unsecured notes................ 225 -- 225 --
Preferred stock................ -- 125 -- 125
- -----------------------------------------------------------------------------
$721 $940 $ 990 $1,141
- -----------------------------------------------------------------------------
Short-term Borrowings, Net ........ $(59) $190 $(447) $ (48)
- -----------------------------------------------------------------------------
Net cash used for the above financing activities increased by $454
million in the second quarter of 2004 from the second quarter of 2003. The
increase in funds used for financing activities resulted from an increase in net
redemptions and refinancings of debt and preferred securities of $449 million.
Redemption and refinancing activities for debt and preferred stock aggregated
approximately $677 million during the second quarter of 2004 (including $189
million of pollution control note repricings). The redemption and refinancing
activities and pollution control note repricings are expected to result in
annualized savings of $35 million. Net cash used for the above financing
activities increased by $457 million in the first six months of 2004 from the
same period of 2003. The increase in funds used for financing activities
resulted primarily from an increase in net redemptions of debt and preferred
securities of $383 million and higher dividend payments in 2004.
FirstEnergy has requirements of approximately $598 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 had approximately $74 million of short-term indebtedness
as of June 30, 2004 compared to approximately $522 million as of December 31,
2003. Unused borrowing capability as of June 30, 2004 included the following:
42
FirstEnergy
Unused Borrowing Capability Holding Company OE Total
- --------------------------------------------------------------------------------
(In millions)
Long-Term Revolving Credit................... $1,375 $375 $1,750
Utilized..................................... -- -- --
Letters of Credit............................ (152) -- (152)
- --------------------------------------------------------------------------------
Net.......................................... 1,223 375 1,598
- -------------------------------------------------------------------------------
Short-Term Bank Facilities................... -- 34 34
Utilized..................................... -- -- --
- -------------------------------------------------------------------------------
Net.......................................... -- 34 34
- -------------------------------------------------------------------------------
Total Unused Borrowing Capability............ $1,223 $409 $1,632
===============================================================================
On June 7, 2004, OE replaced certain collateralized letters of credit
that were issued in 1994 in support of OE's obligations to lessors under the
Beaver Valley Unit 2 sale and leaseback arrangements. Approximately $289 million
in cash collateral and accrued interest previously held by OES Finance
Incorporated, a wholly owned subsidiary of OE, was released on July 15, 2004,
upon cancellation of the existing letters of credit and was used to repay
short-term debt and for other corporate purposes. Simultaneously with the
issuance of the replacement letters of credit, OE entered into a Credit
Agreement pursuant to which a standby letter of credit was issued in support of
the replacement letters of credit, and the issuer of the letters of credit
obtained the right to pledge or assign participations in OE's reimbursement
obligations to a trust. The trust then issued and sold trust certificates to
institutional investors that were designed to be the credit equivalent of an
investment directly in OE.
As of June 30, 2004, the Ohio EUOC and Penn had the aggregate
capability to issue approximately $3.1 billion of additional 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 and Penelec no longer
issue FMB other than as collateral for senior notes, since their senior note
indentures prohibit them (subject to certain exceptions) from issuing any debt
which is senior to the senior notes. As of June 30, 2004, JCP&L and Penelec had
the aggregate capability to issue $1.2 billion of additional senior notes using
FMB collateral. Met-Ed is not limited as to the amount of senior notes it may
issue. Based upon applicable earnings coverage tests in their respective
charters, OE, Penn, and JCP&L could issue a total of $3.6 billion of preferred
stock (assuming no additional debt was issued) as of June 30, 2004. Under its
applicable earnings coverage test, TE could not issue additional preferred
stock. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred
stock.
FirstEnergy restructured its $500 million three-year and $375 million
364-day revolving credit facilities, as well as Ohio Edison's $125 million
364-day revolving credit facility, through a syndicated bank offering that was
completed on June 22, 2004. The new syndicated FirstEnergy facility consists of
a single $1 billion three-year revolving credit facility. Combined with an
existing syndicated $375 million three-year facility for FirstEnergy maturing in
October 2006, a $125 million three-year facility for OE maturing in October
2006, and an existing syndicated $250 million two-year facility for OE maturing
in May 2005, FirstEnergy's primary syndicated credit facilities total $1.75
billion. These facilities, combined with an aggregate $550 million of accounts
receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are
intended to provide liquidity to meet the short-term working capital
requirements of FirstEnergy and its subsidiaries. Total unused borrowing
capability under existing facilities and accounts receivable financing
facilities totaled $2.0 billion as of June 30, 2004.
Borrowings under these facilities are conditioned on FirstEnergy
and/or OE maintaining compliance with certain financial covenants in the
agreements. FirstEnergy and OE 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. FirstEnergy and OE are in
compliance with these financial covenants. As of June 30, 2004, FirstEnergy's
and OE's fixed charge coverage ratios, as defined under the credit agreements,
were 3.73 to 1 and 6.84 to 1, respectively. FirstEnergy's and OE's debt to total
capitalization ratios, as defined under the credit agreements, were 0.57 to 1
and 0.38 to 1, respectively. 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
their business, their condition (financial or otherwise), their results of
operations, or their prospects.
FirstEnergy's and OE's primary credit facilities contain no
provisions restricting their ability to borrow, or accelerating repayment of
outstanding loans, as a result of any change in their S&P or Moody's credit
ratings. 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
43
companies. FESC 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 $1.375 billion of FirstEnergy's revolving credit
facilities. Companies receiving a loan under the money pool agreements must
repay the principal amount of such 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 their respective pool and is based on the average
cost of funds available through the pool. The average interest rate for
borrowings in the second quarter of 2004 was 1.39% for the regulated companies'
pool and 1.54% for the competitive companies' pool.
In April and May of 2004, FirstEnergy executed seven
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 5.89%.
On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes
due 2016. The proceeds of this transaction were used to redeem $40 million of
7.98% JCP&L Series C MTNs due 2023, $40 million of 8.32% JCP&L Series C MTNs due
2022, $50 million of 6.78% JCP&L Series C MTNs due 2005, $160 million of 7.125%
JCP&L FMB due October 1, 2004 and to reduce short term debt.
On June 1, 2004, Met-Ed used a portion of the proceeds from its March
25, 2004 $250 million 4.875% Senior Notes offering to redeem at par $100 million
principal amount of its subordinated debentures in connection with the
concurrent off-balance sheet redemption at par of $100 million principal amount
of Met-Ed Capital Trusts 7.35% Trust Preferred Securities.
On July 30, 2004, Penelec announced it would optionally redeem at par
$100 million principal amount of its subordinated debentures in connection with
the concurrent off-balance sheet redemption at par of $100 million principal
amount of Penelec Capital Trust 7.34% Trust Preferred Securities on September 1,
2004.
On April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted that, in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility
through debt reduction and divestiture of non-core assets, FirstEnergy's
integrated regional strategy, and strong liquidity as credit strengths. Moody's
noted the substantial debt burden associated with the GPU merger, fully
competitive generating markets, and modest growth in markets served as credit
challenges for FirstEnergy. Moody's also noted that a "track record of improving
financial condition, especially a track record of debt reduction, could cause
the ratings to go up" and that the opposite development could cause the ratings
to go down.
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on the Company.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in
response to changes in the industry. As a result of its revised methodology for
evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility
companies including JCP&L and Penn. JCP&L's FMB credit rating was upgraded to
BBB+ from BBB and Penn's FMB credit rating was upgraded to BBB from BBB-.
Cash Flows From Investing Activities
Net cash flows provided from investing activities totaled $72 million
in the second quarter of 2004, compared to net cash flows used of $109 million
for investing activities for the same period of 2003. The $181 million change
primarily resulted from $200 million in cash proceeds from the sale in the
second quarter of 2004 of FirstEnergy's interest in GLEP.
The following table summarizes investments by FirstEnergy's regulated
services and competitive services segments in the second quarter and first six
months of 2004:
44
Summary of Cash Used Property
for Investing Activities Additions Investments Other Total
------------------------------------------------------------------------------
Sources (Uses) (In millions)
Three Months Ended June 30, 2004
Regulated Services.................. $(129) $ 14 $ (5) $(120)
Competitive Services................ (60) 178 (1) 2 120
Other............................... (7) 80 (1) 72
------------------------------------------------------------------------------
Total.......................... $(196) $272 $ (4) $ 72
==============================================================================
Six Months Ended June 30, 2004
Regulated Services.................... $(220) $(65)(2) $ (7) $(292)
Competitive Services.................. (105) 198 (1) 4 97
Other................................. (10) 53 (19) 24
-------------------------------------------------------------------------------
Total............................ $(335) $186 $(22) $(171)
===============================================================================
(1) Includes $200 million in cash proceeds from the sale of GLEP.
(2) Includes a $51 million refunding payment to a NUG trust fund.
During the remaining two quarters of 2004, capital requirements for
property additions and capital leases are expected to be approximately $453
million, including $82 million for nuclear fuel.
FirstEnergy's current forecast reflects expenditures of approximately
$2.3 billion for property additions and improvements from 2004-2006, of which
approximately $708 million is applicable to 2004. Investments for additional
nuclear fuel during the 2004-2006 period are estimated to be approximately $300
million, of which approximately $82 million applies to 2004. During the same
periods, the Companies' nuclear fuel investments are expected to be reduced by
approximately $274 million and $89 million, respectively, as the nuclear fuel is
consumed.
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy and the Companies
enter into various agreements to provide financial or performance assurances to
third parties. Such agreements include contract guarantees, surety bonds, and
ratings contingent collateralization provisions.
As of June 30, 2004, the maximum potential future payments under
outstanding guarantees and other assurances totaled approximately $2.1 billion
as summarized below:
Maximum
Guarantees and Other Assurances Exposure
------------------------------------------------------------
(In millions)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts (1)..... $ 850
Other (2)................................... 149
--------------------------------------------------------
999
Surety Bonds.................................. 257
Letters of Credit (3)(4)...................... 816
--------------------------------------------------------
Total Guarantees and Other Assurances....... $2,072
========================================================
(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 $152 million issued for various
terms under letter of credit capacity available in FirstEnergy's
syndicated revolving credit facilities.
(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 an unsecured letter of credit of $237 million
pledged in connection with the sale and leaseback of
Beaver Valley Unit 2 by OE and unsecured letters of
credit of $211 million pledged in connection with the
sale and leaseback of Perry Unit 1 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
45
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 June 30, 2004:
Total Collateral Paid
-------------------------- Remaining
Collateral Provisions Exposure (1) Cash Letters of Credit Exposure
(In millions)
Rating downgrade......... $270 $161 $18 $ 91
Adverse event............ 180 -- 23 157
- -----------------------------------------------------------------------------
Total.................... $450 $161 $41 $248
=============================================================================
(1) As of July 12, 2004, FirstEnergy's total exposure decreased to
$437 million and the remaining exposure decreased to $240
million - net of $156 million of cash collateral and $41
million of letters of credit collateral provided to
counterparties.
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.
On July 15, 2004, FirstEnergy received $289 million of cash
(principal and interest) for maturing OE certificates of deposit. These
certificates of deposit related to OE's Beaver Valley Unit 2 sale and leaseback
financing. Cash collateralized letters of credit associated with that financing
were cancelled and replaced by unsecured letters of credit totaling
approximately $237 million during the second quarter of 2004.
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.
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. The present value of
these sale and leaseback operating lease commitments, net of trust investments,
total $1.4 billion as of June 30, 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 $178
million of off-balance sheet financing as of June 30, 2004.
FirstEnergy has equity ownership interests in 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
46
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 second quarter and first six months of
2004 is summarized in the following table:
Increase (Decrease) in the Fair Value
Of Commodity Derivative Contracts
Three Months Ended Six Months Ended
June 30, 2004 June 30, 2004
--------------------------- ---------------------------
Non-Hedge Hedge Total Non-Hedge Hedge Total
--------- ----- ----- --------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net asset at beginning of period........... $64 $ 12 $ 76 $67 $ 12 $ 79
New contract value when entered........................ -- -- -- -- -- --
Additions/change in value of existing contracts........ (1) 2 1 (5) 8 3
Change in techniques/assumptions....................... -- -- -- -- -- --
Settled contracts...................................... (1) (6) (7) -- (12) (12)
------------------------ --------------------------
Outstanding net asset at end of period (1)............. 62 8 70 62 8 70
----------------------- -------------------------
Non-commodity Net Assets at End of Period:
Interest Rate Swaps (2)............................. -- (51) (51) -- (51) (51)
----------------------- ---------------------------
Net Assets - Derivative Contracts at End of Period..... $62 $(43) $ 19 $62 $(43) $ 19
======================= =======================
Impact of Changes in Commodity Derivative Contracts (3)
Income Statement Effects (Pre-Tax)..................... $(2) $ -- $ (2) $(4) $ -- $ (4)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................... $-- $ (4) $ (4) $-- $ (4) $ (4)
Regulatory Liability................................... $-- $ -- $ -- $(1) $ -- $ (1)
(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) 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 June
30, 2004 as follows:
Non-Hedge Hedge Total
----------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $ 9 $ 6 $ 15
Other Liabilities................. (8) -- (8)
Non-Current-
Other Deferred Charges............ 61 2 63
Other Liabilities................. -- (51) (51)
----------------------------------------------------------------------
Net assets........................ $ 62 $(43) $ 19
======================================================================
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 commodity derivative contracts by year are summarized in the
following table:
47
Source of Information
- - Fair Value by Contract Year 2004(1) 2005 2006 2007 Thereafter Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Prices actively quoted(2)............. $ 3 $ 4 $-- $-- $-- $ 7
Other external sources(3)............. 9 11 10 -- -- 30
Prices based on models................ -- -- -- 10 23 33
- ---------------------------------------------------------------------------------------------------------
Total(4)........................... $12 $15 $10 $10 $23 $70
=========================================================================================================
(1) For the last two 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.
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 June 30, 2004.
Based on derivative contracts held as of June 30, 2004, an adverse 10% change in
commodity prices would decrease net income by approximately $1 million during
the next twelve months.
Interest Rate Swap Agreements
During the second 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 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 $9
million lower in the second quarter of 2004, compared to being $8 million lower
in the second quarter of 2003. As of June 30, 2004, the debt underlying the
interest rate swaps had a weighted average fixed interest rate of 5.53%, which
the swaps have effectively converted to a current weighted average variable
interest rate of 2.66%.
June 30, 2004 December 31, 2003
---------------------------- -----------------------------
Notional Maturity Fair Notional Maturity Fair
Interest Rate Swaps Amount Date Value Amount Date Value
- ---------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed to Floating Rate
(Fair value hedges) $ 200 2006 $ (2) $ 200 2006 $ 1
100 2008 (2) 50 2008 --
100 2010 (2) 100 2010 1
100 2011 (1) 100 2011 1
450 2013 (14) 350 2013 (1)
100 2014 (2)
150 2015 (14) 150 2015 (10)
200 2016 (2)
150 2018 (4) 150 2018 1
50 2019 (1) 50 2019 1
50 2031 (3)
50 2039 (4)
-------------------------------------------------------------------------------------------
$1,700 $(51) $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 trust investments are marketable
equity securities carried at their market value of approximately $851 million
and $779 million as of June 30, 2004 and December 31, 2003, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in an
$85 million reduction in fair value as of June 30, 2004.
48
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 rating for energy
contract counterparties of "BBB" (S&P). As of June 30, 2004, the largest credit
concentration with any counterparty relationship was 7% - that counterparty is
currently rated investment grade.
OUTLOOK
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in the
EUOCs' respective state regulatory plans. However, despite these similarities,
the specific approach taken by each state and for each of the EUOC varies. Those
provisions include:
o allowing the EUOC's electric customers to select their
generation suppliers;
o establishing PLR obligations to non-shopping customers in
the EUOC's service areas;
o allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
o deregulating the EUOC's electric generation businesses;
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 (or to be requested for authorization in the case
of ATSI) 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:
June 30, December 31, Increase
Regulatory Assets 2004 2003 (Decrease)
---------------------------------------------------------------------
(In millions)
OE..................... $1,267 $1,451 $(184)
CEI.................... 1,001 1,056 (55)
TE..................... 416 459 (43)
Penn................... 8 28 (20)
JCP&L.................. 2,324 2,558 (234)
Met-Ed................. 946 1,028 (82)
Penelec................ 411 497 (86)
ATSI................... 11 - 11
-------------------------------------------------------------------
Total.................. $6,384 $7,077 $(693)
====================================================================
49
Regulatory assets by source are as follows:
June 30, December 31, Increase
Regulatory Assets By Source 2004 2003 (Decrease)
------------------------------------------------------------------------------
(In millions)
Regulatory transition charge................$5,688 $6,427 $(739)
Customer shopping incentives................ 465 371 94
Customer receivables for future income taxes 300 340 (40)
Societal benefits charge.................... 87 81 6
Loss on reacquired debt..................... 80 75 5
Postretirement benefits..................... 71 77 (6)
Nuclear decommissioning, decontamination
and spent fuel disposal costs............. (86) (96) 10
Component removal costs..................... (333) (321) (12)
Property losses and unrecovered plant costs. 60 70 (10)
Other....................................... 52 53 (1)
------------------------------------------------------------------------------
Total $6,384 $7,077 $(693)
===============================================================================
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
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, was an independent review to identify areas
recommended for reliability improvement. The final audit report was completed on
May 6, 2004. The report identified positive observations and included various
recommendations for reliability improvement. FirstEnergy implemented the audit
results and recommendations relating to summer 2004 and reported completion of
those recommendations on June 30, 2004, with one exception related to MISO's
implementation of a voltage stability tool expected to be finalized later this
year. Implementation of the recommendations has not required incremental
material investment or upgrades to existing equipment.
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 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
On April 22, 2004, FirstEnergy filed with the 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 2009. FirstEnergy is continuing to review
the results of that study related to 2009 and completed the implementation
of recommendations relating to 2004 by June 30, 2004. 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,
50
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
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 (SRM) be hired to oversee the investigation. On
December 8, 2003, the SRM 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 and
procedures of JCP&L. The audit was expanded to include the July 2003 outage and
was completed in January 2004. On June 9, 2004, the NJBPU approved a stipulation
that incorporated the final SRM report and portions of the final Booth report.
JCP&L is awaiting the final NJBPU order.
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 required additional reporting
on reliability. The PPUC ordered all Pennsylvania utilities to begin filing
quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
approving the revised reliability benchmark and standards, including revised
benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted
Pennsylvania utilities to file in a separate proceeding to revise the recomputed
benchmarks and standards if they have evidence, such as the impact of automated
outage management systems, on the accuracy of the PPUC computed reliability
indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks
with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards
due to their implementation of automated outage management systems following
restructuring. No procedural schedule or hearing date has been set for this
proceeding. FirstEnergy is unable to predict the outcome of this proceeding.
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 was filed May 7, 2004.
On June 21, 2004, intervenors filed rebuttal testimony and Met-Ed's, Penelec's
and Penn's surrebuttal testimony was filed on July 23, 2004. Hearings
were held in early August 2004 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 the end of 2004. FirstEnergy is unable to predict the
outcome of the investigation or the impact of the PPUC order.
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 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.
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 through an extension of the regulatory transition
charge.
51
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 that proposal, the Ohio EUOC requested:
o Extension of the transition cost amortization period for OE
from 2006 to 2007; for CEI from 2008 to 2009 and for TE from
mid-2007 to 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 February 23, 2004, after consideration of the 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. On June
9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan,
subject to conducting a competitive bid process on or before December 1, 2004.
In addition to requiring the competitive bid process, the PUCO made other
modifications to FirstEnergy's revised Rate Stabilization Plan application.
Among the major modifications were the following:
o Limiting the ability of the Ohio EUOC to request
adjustments in generation charges during 2006 through 2008
for increases in taxes;
o Expanding the availability of market support generation;
o Revising the kilowatt-hour target level and the time
period for recovering regulatory transition charges;
o Establishing a 3-year competitive bid process for
generation;
o Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008;
and
o Denying the ability to defer costs for future recovery of
distribution reliability improvement expenditures.
On June 18, 2004, the Ohio EUOC filed with the PUCO an application
for rehearing of the modified version of the Rate Stabilization Plan. Several
other parties also filed applications for rehearing. On August 4, 2004, the PUCO
issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications
included the following:
o Expanding the Ohio EUOC's ability to request adjustments
in generation charges during 2006 through 2008 to include
increases in the cost of fuel (including the cost of
emission allowances consumed, lime, stabilizers and other
additives and fuel disposal) using 2002 as the base year.
Any increases in fuel costs would be subject to downward
adjustments in subsequent years should fuel costs decline,
but not below the generation rate initially established in
the Rate Stabilization Plan;
o Approving the revised kilowatt-hour target level and time
period for recovery of regulatory transition costs as
presented by the Ohio EUOC in their rehearing application;
o Retaining the requirement for expanded availability of
market support generation, but adopting the Ohio EUOC's
alternative approach that conditions expanded availability
on higher pricing and eliminating the requirement to
reduce the interest deferral for certain affected rate
schedules;
52
o Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules;
and
o Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances.
On August 5, 2004, FirstEnergy accepted the Rate Stabilization Plan
as modified and approved by the PUCO on August 4, 2004. FirstEnergy retains the
right to withdraw the modified Rate Stabilization Plan should subsequent adverse
action be taken by the PUCO or a court. In the second quarter of 2004, the Ohio
EUOC implemented the accounting modifications contained in the PUCO's June 9,
2004 Order, which are consistent with the PUCO's August 4, 2004 Entry on
Rehearing. Those modifications included amortization of transition costs based
on extended amortization periods (that are no later than 2007 for OE, mid-2009
for CEI and mid-2008 for TE) and the deferral of interest costs on the
accumulated deferred shopping incentives.
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. 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 the subsequent six to twelve months.
During that period, JCP&L would 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 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 charge. 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 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. In its final decision and order issued on May 17, 2004, the NJBPU
clarified the method for calculating interest attributable to the cost
disallowances, resulting in a $5.4 million reduction from the amount estimated
in 2003. On June 1, 2004, JCP&L filed with the NJBPU a supplemental and amended
motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted
limited reconsideration and rehearing on the following issues: (1) deferred
costs disallowances, (2) the capital structure including the rate of return, (3)
merger savings, (4) amortization of costs to achieve merger savings; and (5)
decommissioning. All other issues included in JCP&L's amended motion were
denied. Oral arguments were held on August 4, 2004. Management cannot predict
when a decision following the oral arguments may be announced by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU
which requested an increase in base rates of $36 million, reflecting the
recovery of system reliability costs and a higher return on equity. The filing
also requests an increase to the MTC deferred balance recovery of approximately
$20 million annually. The filing fulfills the NJBPU requirement that a Phase II
proceeding be conducted and that any expenditures and projects undertaken by
JCP&L to increase its system reliability be reviewed.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed
testimony on June 7, 2004 supporting a continuation of the current level and
duration of the funding of TMI-2 decommissioning costs by JCP&L's customers
without a reduction, termination or capping of the funding.
Pennsylvania
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 reversed 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
53
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 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 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 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.
Met-Ed and Penelec purchase a portion of their PLR requirements from
FES through a wholesale power sale agreement. The PLR sale is 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 retains 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.
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
54
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.
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 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. These cases are referred to as New Source Review
cases. 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 trial to address civil penalties and what, if any,
actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated in its August 2003
ruling 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. While the parties are engaged in meaningful
settlement discussions, management is unable to predict the ultimate outcome of
this matter and no liability has been accrued as of June 30, 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 wave
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
55
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 were appealed to the Appellate Division.. The Appellate Court
issued a decision on July 8, 2004, affirming the decertification of the
originally certified class but remanding for certification of a class limited to
those customers directly impacted by the outages of transformers in Red Bank,
New Jersey. On July 28, 2004, both plaintiffs and JCP&L appealed the decision of
the Appellate Division to the New Jersey Supreme Court. FirstEnergy is unable to
predict the outcome of these matters and no liability has been accrued as of
June 30, 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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Regulatory Matters
above). FirstEnergy's implementation of these recommendations included
completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 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. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004.
As part of its informal inquiry, which began in September 2003, the
SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy
voluntarily provide information and documents related to the Davis-Besse outage.
FirstEnergy is complying with this request and continues to cooperate fully with
this inquiry. 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, including claims for asbestos exposure, 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.
Various legal proceedings alleging violations of federal securities
laws and related state laws were 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
56
Station. The lawsuits were filed against FirstEnergy and certain of its officers
and directors. On July 27, 2004, FirstEnergy announced that it had reached an
agreement to resolve these pending lawsuits. The settlement agreement, which
does not constitute any admission of wrongdoing, provides for a total settlement
payment of $89.9 million. Of that amount, FirstEnergy's insurance carriers will
pay $71.92 million, based on a contractual pre-allocation, and FirstEnergy will
pay $17.98 million, which resulted in a charge against FirstEnergy's second
quarter 2004 earnings of $0.03 per share of common stock. The federal securities
cases were consolidated into a single action, as were the federal derivative
cases; those actions are pending in federal court in Akron. Two state court
derivative cases are also pending. The settlement is subject to court approval
and, although not anticipated to occur, in the event that a significant number
of shareholders do not accept the terms of the settlement, FirstEnergy and
individual defendants have the right, but not the obligation, to set aside the
settlement and recommence the litigation.
FirstEnergy's Ohio utility subsidiaries were 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.
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. 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 by alternative suppliers.
57
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. FirstEnergy reduced its 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
half 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
is not required to fund its pension plans in 2004.
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 initial 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 Rate Stabilization 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 judgment 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.
58
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 FCON 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, 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
unit's goodwill and the carrying value of the goodwill. FirstEnergy's most
recent 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. In the first half of 2004, FirstEnergy reduced goodwill by $27
million for pre-merger interest received on an income tax refund and other tax
benefits. As of June 30, 2004, FirstEnergy had $6.1 billion of goodwill that
primarily relates to its regulated services segment.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
Exposure Draft of Proposed Statement of Financial Accounting Standards
- Share-Based Payment - an amendment of FASB Statements No. 123 and 95
During March 2004, the FASB issued an exposure draft of a new
standard, which would amend SFAS 123 and SFAS 95. Among other items, the new
standard would require expensing stock options in FirstEnergy's financial
statements. The new standard, as proposed, would be effective January 1, 2005,
for calendar year companies. FirstEnergy will not be able to determine the exact
impact of the proposed standard on its results of operations until the standard
is issued in final form. The impact of the fair value recognition provisions of
SFAS 123 on FirstEnergy's net income and earnings per share for the current
reporting periods is disclosed in Note 2.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the
EITF on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. FirstEnergy has
available-for-sale securities with unrealized losses of approximately $21
million as of June 30, 2004 that will be evaluated in accordance with EITF 03-1
in the third quarter of 2004.
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 was effective for fiscal periods beginning after March 31,
2004 and had no impact on FirstEnergy's computation of earnings per share.
59
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on accounting for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. The effect of the federal subsidy provided under the Medicare Act
on FirstEnergy's consolidated financial statements is described in Note 4.
FIN 46 (revised December 2003), "Consolidation of Variable
Interest Entities"
In December 2003, the FASB issued a revised interpretation of ARB 51,
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 consolidated financial statements.
60
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ------------------------
2004 2003 2004 2003
-------- -------- ---------- -----------
(In thousands)
OPERATING REVENUES........................................ $718,347 $673,708 $1,461,642 $1,416,451
-------- -------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 13,844 10,290 28,914 23,140
Purchased power........................................ 237,826 216,355 487,707 460,183
Nuclear operating costs................................ 77,297 118,209 154,033 243,577
Other operating costs.................................. 92,778 80,327 177,157 170,600
Provision for depreciation and amortization............ 105,172 105,753 229,901 214,138
General taxes.......................................... 39,488 44,406 88,054 92,662
Income taxes........................................... 65,787 34,379 127,361 78,080
-------- -------- ---------- ----------
Total operating expenses and taxes................... 632,192 609,719 1,293,127 1,282,380
-------- -------- ---------- ----------
OPERATING INCOME.......................................... 86,155 63,989 168,515 134,071
OTHER INCOME.............................................. 20,673 15,411 33,144 28,912
NET INTEREST CHARGES:
Interest on long-term debt............................. 16,395 24,957 32,984 49,445
Allowance for borrowed funds used during construction
and capitalized interest............................. (1,593) (1,124) (2,974) (2,504)
Other interest expense................................. 4,046 9,325 6,936 11,803
Subsidiaries' preferred stock dividend requirements.... 640 912 1,280 1,824
--------- -------- ---------- ----------
Net interest charges................................. 19,488 34,070 38,226 60,568
-------- -------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE...................................... 87,340 45,330 163,433 102,415
Cumulative effect of accounting change (net of income
taxes of $22,389,000) (Note 2)......................... -- -- -- 31,720
--------- -------- ---------- ----------
NET INCOME................................................ 87,340 45,330 163,433 134,135
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 659 659 1,220 1,318
-------- -------- ---------- ----------
EARNINGS ON COMMON STOCK.................................. $ 86,681 $ 44,671 $ 162,213 $ 132,817
======== ======== ========== ==========
COMPREHENSIVE INCOME:
NET INCOME................................................ $ 87,340 $ 45,330 $ 163,433 $ 134,135
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- (86,076) -- (86,076)
Unrealized gain (loss) on available for
sale securities...................................... (1,021) 20,481 4,146 15,306
-------- -------- ---------- ----------
Other comprehensive income (loss).................... (1,021) (65,595) 4,146 (70,770)
Income tax related to other comprehensive income....... 421 27,066 (1,709) 29,188
-------- -------- ---------- ----------
Other comprehensive income (loss), net of tax........ (600) (38,529) 2,437 (41,582)
-------- -------- ---------- ----------
TOTAL COMPREHENSIVE INCOME................................ $ 86,740 $ 6,801 $ 165,870 $ 92,553
======== ======== ========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these statements.
61
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service...................................................................... $5,328,231 $5,269,042
Less-Accumulated provision for depreciation..................................... 2,645,772 2,578,899
---------- ----------
2,682,459 2,690,143
---------- ----------
Construction work in progress-
Electric plant................................................................ 164,953 145,380
Nuclear Fuel.................................................................. 554 554
---------- ----------
165,507 145,934
---------- ----------
2,847,966 2,836,077
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds............................................ 370,183 383,510
Certificates of deposit......................................................... -- 277,763
Nuclear plant decommissioning trusts............................................ 399,519 376,367
Long-term notes receivable from associated companies ........................... 208,742 508,594
Other........................................................................... 53,971 59,102
---------- ----------
1,032,415 1,605,336
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents....................................................... 1,664 1,883
Certificates of deposit......................................................... 277,763 --
Receivables-
Customers (less accumulated provisions of $8,409,000 and $8,747,000,
respectively, for uncollectible accounts).................................. 275,038 280,538
Associated companies.......................................................... 372,453 436,991
Other (less accumulated provisions of $1,867,000 and $2,282,000,
respectively, for uncollectible accounts).................................. 22,574 28,308
Notes receivable from associated companies...................................... 257,563 366,501
Materials and supplies, at average cost......................................... 85,679 79,813
Prepayments and other........................................................... 20,904 14,390
---------- ----------
1,313,638 1,208,424
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................... 1,275,435 1,477,969
Property taxes.................................................................. 59,279 59,279
Unamortized sale and leaseback costs............................................ 62,937 65,631
Other........................................................................... 65,722 64,214
---------- ----------
1,463,373 1,667,093
---------- ----------
$6,657,392 $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.......................................... (36,256) (38,693)
Retained earnings............................................................. 514,147 522,934
---------- ----------
Total common stockholder's equity........................................... 2,576,620 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.................................. 1,000,114 1,179,789
---------- ----------
3,676,804 3,862,829
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt ............................................... 559,640 466,589
Short-term borrowings-
Associated companies.......................................................... 33,537 11,334
Other......................................................................... 71,524 171,540
Accounts payable-
Associated companies.......................................................... 177,281 271,262
Other......................................................................... 8,175 7,979
Accrued taxes................................................................... 217,891 560,345
Accrued interest................................................................ 18,604 18,714
Other........................................................................... 64,550 58,680
---------- ----------
1,151,202 1,566,443
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes............................................... 790,711 867,691
Accumulated deferred investment tax credits..................................... 69,507 75,820
Asset retirement obligation..................................................... 328,243 317,702
Retirement benefits............................................................. 349,058 331,829
Other........................................................................... 291,867 294,616
---------- ----------
1,829,386 1,887,658
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................. ---------- ----------
---------- ----------
$6,657,392 $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.
62
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2004 2003 2004 2003
--------- --------- --------- ----------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 87,340 $ 45,330 $ 163,433 $ 134,135
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation and amortization........ 105,172 105,753 229,901 214,138
Nuclear fuel and lease amortization................ 10,591 10,763 21,852 17,869
Deferred income taxes, net......................... (16,895) (28,387) (43,282) (20,704)
Investment tax credits, net........................ (3,647) (3,692) (7,305) (7,396)
Cumulative effect of accounting change (Note 2).... -- -- -- (54,109)
Receivables........................................ 127,707 (350,873) 75,772 (380,782)
Materials and supplies............................. (3,104) 6,969 (5,866) 5,671
Deferred lease costs............................... (35,482) (34,360) (2,452) (2,677)
Prepayments and other current assets............... 5,315 5,094 (6,514) (9,799)
Accounts payable................................... (334,764) 240,948 (93,785) 255,418
Accrued taxes...................................... (30,877) 43,083 (342,454) 49,134
Accrued interest................................... (5,553) (7,543) (110) (5,106)
Accrued retirement benefit obligations............. 6,106 8,502 17,229 11,181
Accrued compensation, net.......................... (372) (2,714) 4,032 (8,516)
Other.............................................. (11,740) 28,503 1,248 22,965
--------- ---------- ---------- ----------
Net cash provided from (used for)
operating activities........................... (100,203) 67,376 11,699 221,422
--------- ---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- 575,000 30,000 575,000
Short-term borrowings, net........................... -- 13,688 -- --
Redemptions and Repayments-
Long-term debt....................................... (19,809) (238,963) (116,810) (258,456)
Short-term borrowings, net........................... (94,155) -- (77,814) (218,590)
Dividend Payments-
Common stock......................................... (117,000) (272,000) (171,000) (285,000)
Preferred stock...................................... (659) (659) (1,220) (1,318)
--------- ---------- ---------- ----------
Net cash provided from (used for)
financing activities........................... (231,623) 77,066 (336,844) (188,364)
--------- ---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (47,302) (33,327) (84,963) (101,694)
Contributions to nuclear decommissioning trusts........ (7,885) -- (15,770) (7,885)
Nuclear decommissioning trust investments.............. 337 (21,620) (6,542) (17,372)
Loan repayments from (loans to) associated
companies, net ....................................... 359,878 (121,971) 408,790 51,279
Other.................................................. 27,139 20,520 23,411 24,466
--------- ---------- ----------- ----------
Net cash provided from (used for)
investing activities........................... 332,167 (156,398) 324,926 (51,206)
--------- ---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents...... 341 (11,956) (219) (18,148)
Cash and cash equivalents at beginning of period.......... 1,323 14,320 1,883 20,512
--------- ---------- ---------- ----------
Cash and cash equivalents at end of period................ $ 1,664 $ 2,364 $ 1,664 $ 2,364
========= ========== ========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these statements.
63
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related consolidated
statements of income and comprehensive income and cash flows for each of the
three-month and six-month periods ended June 30, 2004 and 2003. These interim
financial statements are the responsibility of the Company's management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 the standards of the Public Company
Accounting Oversight Board (United States), 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 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
August 6, 2004
64
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 some
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 second quarter of 2004 increased to
$87 million from $45 million in the second quarter of 2003. During the first six
months of 2004, earnings on common stock increased to $162 million from $133
million in the same period of 2003. In the first six months of 2003, earnings on
common stock 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 $102 million in the first six months of 2003.
Results in the second quarter and the first six months of 2004,
compared to the same periods in 2003, improved due to higher operating revenues,
reduced financing costs and lower nuclear operating expenses as a result of
additional outage-related work at the nuclear generating plants in 2003.
Partially offsetting these improvements were increased purchased power costs,
higher nuclear fuel expenses and increased other operating costs.
Operating revenues increased by $44.6 million or 6.6% in the second
quarter of 2004 compared with the same period in 2003. The higher revenues
primarily resulted from additional wholesale sales to FES ($28.6 million) due to
increased nuclear generation available for sale, partially offset by lower
revenues from nonaffiliate wholesale customers ($7.7 million) principally due to
the expiration of a contract in July 2003. The increased nuclear generation in
2004 was due to refueling outages last year at Beaver Valley Unit 1 and Perry.
Contributing to the increase in revenues were higher retail generation sales
which increased revenues by $14.8 million. Kilowatt-hour sales to retail
customers increased by 7.0% due to a stronger economy in OE's service area, the
decline of sales by alternative suppliers as a percentage of total sales (1.7
percentage points) and warmer weather in the second quarter 2004. In the first
six months of 2004, operating revenues increased by $45.2 million or 3.2%.
Revenues from wholesale sales to FES increased by $44.5 million, which were
partially offset by the expired contract that reduced wholesale revenues by $11
million. Retail generation sales revenues increased by $12.3 million reflecting
the effect of increased unit prices and increased sales in the commercial and
industrial customer sectors, partially offset by lower residential sales. The
increased consumption for the first half of 2004 was primarily due to a stronger
economy and warmer weather in the second quarter of 2004.
Distribution deliveries increased 4.5% in the second quarter of 2004
and 1.2% in the first six months of 2004 compared with the corresponding periods
of 2003 with increases in all retail customer categories. Revenues from
electricity throughput increased by $11.4 million in the second quarter and $5.5
million in the first half of 2004 compared to the same periods of 2003.
Changes in electric generation sales and distribution deliveries in
the second quarter and first six months of 2004 from the corresponding periods
of 2003 are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Six Months
--------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail............................... 7.0% 1.3%
Wholesale............................ 25.3% 16.5%
------------------------------------------------------------------
Total Electric Generation Sales........ 15.3% 8.1%
==================================================================
Distribution Deliveries:
Residential.......................... 7.8% 1.8%
Commercial........................... 5.3% 2.2%
Industrial........................... 1.7% --
-------------------------------------------------------------------
Total Distribution Deliveries.......... 4.5% 1.2%
==================================================================
65
Operating Expenses and Taxes
Total operating expenses and taxes increased $22 million in the
second quarter and $11 million in the first six months of 2004 from the same
periods last year. The following table presents changes from the prior year by
expense category.
Operating Expenses and Taxes - Changes Three Months Six Months
----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................ $ 4 $ 6
Purchased power costs........................... 22 28
Nuclear operating costs......................... (41) (90)
Other operating costs........................... 12 7
------------------------------------------------------------------------
Total operation and maintenance expenses...... (3) (49)
Provision for depreciation and amortization..... (1) 16
General taxes................................... (5) (5)
Income taxes.................................... 31 49
------------------------------------------------------------------------
Net increase in operating expenses and taxes.. $ 22 $ 11
========================================================================
Higher fuel costs in the second quarter and first six months of 2004,
compared with the same periods of 2003, resulted from increased nuclear
generation - up 45.8% and 33.2%, respectively. Purchased power costs were higher
in both periods of 2004 reflecting higher unit costs and increased kilowatt-hour
purchases from FES for supply to PLR customers. Lower nuclear operating costs
occurred in large part due to the absence of refueling outages in 2004 -
refueling outages were performed at Beaver Valley Unit 1 (100% ownership) in the
first quarter of 2003 and the Perry plant (35.24% ownership) in the second
quarter of 2003. The increase in other operating costs in the second quarter and
first six months of 2004, compared to the same periods of 2003, is due to higher
employee benefit costs and administrative costs.
Depreciation and amortization increased by $16 million in the first
six months of 2004 compared to the same period of 2003 primarily from four
factors - increased amortization of Ohio transition regulatory assets ($17
million) and decreased regulatory asset deferrals ($3 million), partially offset
by higher shopping incentive deferrals ($0.9 million) and the deferral of
interest costs on accumulated deferred shopping incentives ($5 million). The
interest deferrals were implemented in the second quarter of 2004 (retroactive
to January 1, 2004) pursuant to the Ohio Rate Stabilization Plan.
General taxes decreased in the second quarter and first six months of
2004 from the same periods of 2003 primarily due to refunds received on a real
estate valuation settlement ($6 million).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $15
million in the second quarter and $22 million in the first six months of 2004
from the same periods last year, reflecting redemptions and refinancings since
June 30, 2003. OE's net debt redemptions totaled $28 million during the first
six months of 2004, which will result in annualized savings of $2 million.
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 two 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
There was no change as of June 30, 2004 and December 31, 2003 in OE's
cash and cash equivalents of $2 million.
66
Cash Flows From Operating Activities
Cash provided by operating activities during the second quarter and
first six months of 2004, compared with the corresponding periods in 2003 were
as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -------------------
Operating Cash Flows 2004 2003 2004 2003
----------------------------------------------------------------------------
(In millions)
Cash earnings (1)............ $ 152 $101 $ 383 $284
Working capital and other.... (252) (34) (371) (63)
----------------------------------------------------------------------------
Total........................ $(100) $ 67 $ 12 $221
----------------------------------------------------------------------------
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash from operating activities decreased $167 million in the
second quarter of 2004 due to a $218 million decrease from changes in working
capital partially offset by a $51 million increase in cash earnings. The change
in working capital primarily reflects lower accounts payable and an increase in
accounts receivable from associated companies. A decrease in accrued tax
liabilities also contributed $74 million to the change in working capital
primarily due to an increase in estimated tax payments in the second quarter of
2004 compared with the second quarter of 2003.
Net cash from operating activities decreased $209 million in the
first six months of 2004 due to a $308 million decrease from changes in working
capital partially offset by a $99 million increase in cash earnings. The change
in working capital primarily reflects higher accounts receivable and decreases
in accounts payable and accrued taxes, reflecting changes of $249 million for
the reallocation of tax liabilities between associated companies related to the
tax sharing agreement. The increase in cash earnings in both periods resulted
from higher operating revenues and decreased nuclear operating costs.
Cash Flows From Financing Activities
In the second quarter of 2004, net cash used for financing activities
was $232 million, compared to net cash provided from financing activities of $77
million in the second quarter of 2003. The change resulted from new financing in
2003 partially offset by a net decrease from short-term borrowings. Common stock
dividend payments to FirstEnergy decreased by $155 million in the second quarter
of 2004 compared to the second quarter of 2003.
In the first six months of 2004, net cash used for financing
activities increased to $337 million from $188 million in the same period last
year. The increase resulted from reduced new financings in 2004 offset by lower
payments on short-term borrowings and reduced common stock dividends to
FirstEnergy.
On June 7, 2004, OE replaced certain collateralized letters of credit
that were issued in 1994 in support of OE's obligations to lessors under the
Beaver Valley Unit 2 sale and leaseback arrangements. Approximately $289 million
in cash collateral and accrued interest previously held by OES Finance
Incorporated, a wholly owned subsidiary of OE, was released on July 15, 2004
upon cancellation of the existing letters of credit and was used to repay
short-term debt and for other corporate purposes. Simultaneously with the
issuance of the replacement letters of credit, OE entered into a Credit
Agreement pursuant to which a standby letter of credit was issued in support of
the replacement letters of credit, and the issuer of the letters of credit
obtained the right to pledge or assign participations in OE's reimbursement
obligations to a trust. The trust then issued and sold trust certificates to
institutional investors that were designed to be the credit equivalent of an
investment directly in OE.
OE had approximately $259 million of cash and temporary investments
(which include short-term notes receivable from associated companies) and
approximately $105 million of short-term indebtedness as of June 30, 2004.
Available borrowing capability under bilateral bank facilities totaled $34
million as of June 30, 2004. The OE Companies had the capability to issue $2
billion of additional first mortgage bonds on the basis of property additions
and retired bonds. Based upon applicable earnings coverage tests the OE
Companies could issue up to $3.1 billion of preferred stock (assuming no
additional debt was issued) as of June 30, 2004.
OE's $125 million 364-day revolving credit facility was restructured
through a new syndicated FirstEnergy facility that was completed on June 22,
2004. Combined with an existing syndicated $125 million three-year facility for
OE maturing in October 2006, an existing syndicated $250 million two-year
facility for OE maturing in May 2005 and bank facilities of $34 million, OE's
credit facilities total $409 million, which was unused as of June 30, 2004.
These facilities are intended to provide liquidity to meet the short-term
working capital requirements of OE and its regulated affiliates.
67
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. As of June 30, 2004, OE's fixed
charge coverage ratio, as defined under the credit agreements, was 6.84 to 1.
OE's debt to total capitalization ratio, as defined under the credit agreements,
was 0.38 to 1. 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 contains no provisions restricting its
ability to borrow, or accelerating 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. 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 second quarter of 2004 was 1.39%.
In March 2004, Penn completed a receivables financing arrangement
that provides borrowing capability of 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 June
30, 2004 and matures on March 29, 2005.
On April 1, 2004, $33 million Ohio Water Development Authority 1988
Series B pollution control revenue refunding bonds and $23 million Ohio Air
Quality Development Authority 1988 Series C pollution control revenue refunding
bonds were remarketed and converted to a daily interest rate mode, and separate
letters of credit in support of principal and interest payments on each issue of
bonds were issued. Simultaneously with these remarketings, the issuer of the
letters of credit also extended certain existing letters of credit supporting
$50 million Ohio Air Quality Development Authority 1989 Series A pollution
control revenue refunding bonds and $50 million Ohio Air Quality Development
Authority Series 2000-C pollution control revenue refunding bonds. On June 1,
2004, $108 million Beaver County Industrial Development Authority Series 1999-A
pollution control revenue refunding bonds were remarketed and converted to an
auction rate interest mode, insured with municipal bond insurance and secured
with first mortgage bonds.
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 securities is stable.
On April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted that, in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility via
debt reduction and divestiture of non-core assets, FirstEnergy's integrated
regional strategy, and strong liquidity as credit strengths. Moody's noted the
substantial debt burden associated with the GPU merger, fully competitive
generating markets, and modest growth in markets served as credit challenges for
FirstEnergy. Moody's also noted that a "track record of improving financial
condition, especially a track record of debt reduction, could cause the ratings
to go up" and that the opposite development could cause the ratings to go down.
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
On July 22, 2004, S&P updated its analysis of U.S. utility FMBs in
response to changes in the industry. As a result of its revised methodology for
evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility
companies including Penn. Penn's FMB credit rating was upgraded to BBB from
BBB-.
Cash Flows From Investing Activities
Net cash provided from investing activities totaled $332 million in
the first quarter of 2004 and $325 million for the first six months, compared to
net cash of $156 million and $51 million, respectively, used for investing
68
activities for the same periods of 2003. The $488 million change for the second
quarter and $376 million for the first six months, resulted primarily from net
increases in loans from associated companies.
During the last two quarters of 2004, capital requirements for
property additions and capital leases are expected to be about $132 million,
including $45 million for nuclear fuel. OE has additional requirements of
approximately $53 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.
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 June 30, 2004, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $680
million.
Equity Price Risk
- -----------------
Included in OE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $225
million and $209 million as of June 30, 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 June 30, 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
Regulatory Matters
Ohio
Beginning on January 1, 2001, OE's customers were able to choose
their electricity suppliers. 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), and the customer receives a generation charge from the alternative
supplier. Under the recently approved Rate Stabilization Plan, OE has continuing
PLR responsibility to its franchise customers through December 31, 2008.
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 MW of low cost supply to unaffiliated alternative
suppliers who serve customers within its service area. FES acts as an alternate
supplier for a portion of the load in OE's 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 OE's
support of energy efficiency and economic development
efforts.
Under that proposal, OE requested:
o Extension of the transition cost amortization period for
OE from 2006 to 2007;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory
assets; and
69
o Ability to initiate a request to increase generation rates
under certain limited conditions.
On February 23, 2004, after consideration of the PUCO Staff comments
and testimony as well as those provided by some of the intervening parties, OE
made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the
PUCO issued an order approving the revised Rate Stabilization Plan, subject to
conducting a competitive bid process on or before December 1, 2004. In addition
to requiring the competitive bid process, the PUCO made other modifications to
OE's revised Rate Stabilization Plan application. Among the major modifications
were the following:
o Limiting the ability of OE to request adjustments in
generation charges during 2006 through 2008 for increases
in taxes;
o Expanding the availability of market support generation;
o Revising the kilowatt-hour target level and the time
period for recovering regulatory transition charges;
o Establishing a 3-year competitive bid process for
generation;
o Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008;
and
o Denying the ability to defer costs for future recovery of
distribution reliability improvement expenditures.
On June 18, 2004, the Ohio EUOC filed with the PUCO an application
for rehearing of the modified version of the Rate Stabilization Plan. Several
other parties also filed applications for rehearing. On August 4, 2004, the PUCO
issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications
included the following:
o Expanding OE's ability to request adjustments in
generation charges during 2006 through 2008 to include
increases in the cost of fuel (including the cost of
emission allowances consumed, lime, stabilizers and other
additives and fuel disposal) using 2002 as the base year.
Any increases in fuel costs would be subject to downward
adjustments in subsequent years should fuel costs decline,
but not below the generation rate initially established in
the Rate Stabilization Plan;
o Approving the revised kilowatt-hour target level and time
period for recovery of regulatory transition costs as
presented by OE in its rehearing application;
o Retaining the requirement for expanded availability of
market support generation, but adopting OE's alternative
approach that conditions expanded availability on higher
pricing and eliminating the requirement to reduce the
interest deferral for certain affected rate schedules;
o Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules;
and
o Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances.
On August 5, 2004, OE accepted the Rate Stabilization Plan as
modified and approved by the PUCO on August 4, 2004. OE retains the right to
withdraw the modified Rate Stabilization Plan should subsequent adverse action
be taken by the PUCO or a court. In the second quarter of 2004, OE implemented
the accounting modifications contained in the PUCO's June 9, 2004 Order, which
are consistent with the PUCO's August 4, 2004 Entry on Rehearing. Those
modifications included amortization of transition costs based on extended
amortization periods (that are no later than 2007 for OE) and the deferral of
interest costs on the accumulated deferred shopping incentives.
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 were as follows:
70
Regulatory Assets as of
---------------------------------------------------------
June 30, December 31,
Company 2004 2003
---------------------------------------------------------
(In millions)
OE......................... $1,267 $1,450
Penn....................... 8 28
---------------------------------------------------------
Consolidated Total...... $1,275 $1,478
=========================================================
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On February 26 and 27, 2004, OE 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, was an
independent review to identify areas recommended for reliability improvement.
The final audit report was completed on May 6, 2004. The report identified
positive observations and included various recommendations for reliability
improvement. FirstEnergy implemented the audit results and recommendations
relating to summer 2004 and reported completion of those recommendations on June
30, 2004, with one exception related to MISO's implementation of a voltage
stability tool expected to be finalized later this year. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
On March 1, 2004, OE filed, in accordance with a November 25, 2003
order from the PUCO, its 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 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
On April 22, 2004, FirstEnergy filed with the 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 2009. FirstEnergy is continuing to review
the results of that study related to 2009 and completed the implementation
of recommendations relating to 2004 by June 30, 2004. 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
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
71
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 required additional reporting
on reliability. The PPUC ordered all Pennsylvania utilities to begin filing
quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
approving the revised reliability benchmark and standards, including revised
benchmarks and standards for Penn. The Order permitted Pennsylvania utilities to
file in a separate proceeding to revise the recomputed benchmarks and standards
if they have evidence, such as the impact of automated outage management
systems, on the accuracy of the PPUC computed reliability indices. Penn filed a
Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking
amendment of the benchmarks and standards due to their implementation of
automated outage management systems following restructuring. No procedural
schedule or hearing date has been set for this proceeding. Penn is unable to
predict the outcome of this proceeding.
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 was
filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and
Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held
in early August 2004 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 the end of 2004. Penn is unable to predict the outcome of the
investigation or the impact of the PPUC order.
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. These cases are referred to as New Source Review cases. 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 trial to address civil penalties and what, if any,
actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated, in its August 2003
ruling, 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. While the parties are engaged in meaningful
settlement discussions, management is unable to predict the ultimate outcome of
this matter and no liability has been accrued as of June 30, 2004.
The OE Companies believe they 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
72
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) were required to comply by May 31, 2004
with individual state NOx budgets. Pennsylvania submitted a SIP that required
compliance with the state NOx budgets at the OE Companies' Pennsylvania
facilities by May 1, 2003. Ohio submitted a SIP that required compliance with
the state NOx budgets at the OE Companies' Ohio facilities by May 31, 2004. The
OE Companies believe their facilities are complying with the state NOx budgets
through combustion controls and post-combustion controls, including Selective
Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using
emission allowances.
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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives above). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Legal Matters
FirstEnergy's Ohio utility subsidiaries were 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.
Various lawsuits, claims, including claims for asbestos exposure, 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.
73
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. 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 by
alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and post-retirement benefit obligations are
allocated to its subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. OE'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 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. FirstEnergy reduced its 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
half 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.
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 initial 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
74
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 Rate Stabilization 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 judgment 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, 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 FCON 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
- --------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the
EITF on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. OE has
available-for-sale securities with unrealized losses of approximately $1.8
million as of June 30, 2004 that will be evaluated in accordance with EITF 03-1
in the third quarter of 2004.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued May 2004, FSP 106-2 provides guidance on the accounting for
the effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy
provided under the Medicare Act 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 consolidated financial statements. See Note 2 -
Consolidation for a discussion of variable interest entities.
75
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- ------------------------
2004 2003 2004 2003
--------- ---------- ----------- -----------
(In thousands)
OPERATING REVENUES........................................ $ 440,876 $ 412,133 $ 867,411 $ 831,904
--------- ---------- --------- ---------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 19,376 10,812 36,572 24,581
Purchased power........................................ 136,505 131,255 271,182 267,600
Nuclear operating costs................................ 23,246 67,218 51,236 122,579
Other operating costs.................................. 74,909 65,859 143,661 127,758
Provision for depreciation and amortization............ 49,842 53,311 111,618 104,668
General taxes.......................................... 34,480 37,339 73,298 77,052
Income taxes........................................... 25,161 1,792 29,174 9,108
--------- ---------- --------- ---------
Total operating expenses and taxes................. 363,519 367,586 716,741 733,346
--------- ---------- --------- ---------
OPERATING INCOME.......................................... 77,357 44,547 150,670 98,558
OTHER INCOME.............................................. 9,494 4,684 21,221 9,425
NET INTEREST CHARGES:
Interest on long-term debt............................. 36,695 39,299 68,906 79,939
Allowance for borrowed funds used during construction.. (1,015) (1,637) (2,726) (3,804)
Other interest expense ................................ 1,446 5 7,511 36
Subsidiaries' preferred stock dividend requirements.... -- 2,250 -- 7,200
--------- ---------- --------- ---------
Net interest charges............................... 37,126 39,917 73,691 83,371
--------- ---------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE................................................. 49,725 9,314 98,200 24,612
Cumulative effect of accounting change (net of income
taxes of $30,168,000) (Note 2)......................... -- -- -- 42,378
--------- ---------- --------- ---------
NET INCOME................................................ 49,725 9,314 98,200 66,990
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 1,755 1,864 3,499 1,105
--------- ---------- --------- ---------
EARNINGS ON COMMON STOCK.................................. $ 47,970 $ 7,450 $ 94,701 $ 65,885
========= ========== ========= =========
COMPREHENSIVE INCOME:
NET INCOME................................................ $ 49,725 $ 9,314 $ 98,200 $ 66,990
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- 24,171 -- 24,171
Unrealized gain (loss) on available for sale securities (10,371) 23,248 (2,323) 18,953
--------- ---------- -------- ---------
Other comprehensive income (loss).................... (10,371) 47,419 (2,323) 43,124
Income tax related to other comprehensive income....... 4,248 (19,924) 952 (18,163)
--------- ---------- -------- ---------
Other comprehensive income (loss), net of tax........ (6,123) 27,495 (1,371) 24,961
--------- ---------- --------- ---------
TOTAL COMPREHENSIVE INCOME................................ $ 43,602 $ 36,809 $ 96,829 $ 91,951
========= ========== ========= =========
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.
76
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $4,351,703 $4,232,335
Less-Accumulated provision for depreciation.................................... 1,909,028 1,857,588
----------- -----------
2,442,675 2,374,747
---------- ----------
Construction work in progress-
Electric plant............................................................... 96,031 159,897
Nuclear fuel................................................................. -- 21,338
---------- ----------
96,031 181,235
---------- ----------
2,538,706 2,555,982
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes..................................................... 584,950 605,915
Nuclear plant decommissioning trusts........................................... 334,808 313,621
Long-term notes receivable from associated companies........................... 97,112 107,946
Other.......................................................................... 17,686 23,636
---------- ----------
1,034,556 1,051,118
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 200 24,782
Receivables-
Customers.................................................................... 8,505 10,313
Associated companies......................................................... 35,303 40,541
Other (less accumulated provisions of $854,000 and $1,765,000, respectively,
for uncollectible accounts)................................................ 82,382 185,179
Notes receivable from associated companies..................................... 502 482
Materials and supplies, at average cost........................................ 56,089 50,616
Prepayments and other.......................................................... 2,614 4,511
---------- ----------
185,595 316,424
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 1,000,438 1,056,050
Goodwill....................................................................... 1,693,629 1,693,629
Property taxes................................................................. 77,122 77,122
Other.......................................................................... 23,828 23,123
---------- ----------
2,795,017 2,849,924
---------- ----------
$6,553,874 $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....................................... 1,282 2,653
Retained earnings............................................................ 443,916 494,212
---------- ----------
Total common stockholder's equity........................................ 1,727,160 1,778,827
Preferred stock not subject to mandatory redemption............................ 96,404 96,404
Long-term debt and other long-term obligations................................. 1,953,730 1,884,643
---------- ----------
3,777,294 3,759,874
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt .............................................. 379,934 387,414
Accounts payable-
Associated companies......................................................... 187,274 245,815
Other........................................................................ 7,535 7,342
Notes payable to associated companies.......................................... 117,458 188,156
Accrued taxes................................................................. 165,657 202,522
Accrued interest............................................................... 38,719 37,872
Lease market valuation liability............................................... 60,200 60,200
Other.......................................................................... 41,546 76,722
---------- ----------
998,323 1,206,043
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 484,795 486,048
Accumulated deferred investment tax credits.................................... 63,503 65,996
Asset retirement obligation.................................................... 263,336 254,834
Retirement benefits............................................................ 113,147 105,101
Lease market valuation liability............................................... 698,300 728,400
Other.......................................................................... 155,176 167,152
---------- ----------
1,778,257 1,807,531
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)............................... ---------- ----------
---------- ----------
$6,553,874 $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.
77
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2004 2003 2004 2003
-------- -------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 49,725 $ 9,314 $ 98,200 $ 66,990
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 49,842 53,311 111,618 104,668
Nuclear fuel and capital lease amortization........ 7,509 2,995 12,616 8,039
Other amortization................................. (4,818) (409) (9,541) (5,022)
Deferred operating lease costs, net................ (223) (222) (41,858) (41,825)
Deferred income taxes, net......................... 3,659 133 866 33,937
Amortization of investment tax credits............. (1,247) (1,201) (2,493) (2,403)
Accrued retirement benefit obligations............. 2,314 (17,684) 8,046 (15,887)
Accrued compensation, net.......................... 476 (6,892) 1,929 (4,312)
Cumulative effect of accounting charge (Note 2).... -- -- -- (72,547)
Receivables........................................ (33,923) (163,454) 109,843 (148,212)
Materials and supplies............................. (3,118) 10,939 (5,473) 10,811
Prepayments and other current assets............... 2 (579) 1,897 1,193
Accounts payable................................... (80,735) 223,375 (58,348) 179,246
Accrued taxes...................................... 31,061 (15,458) (36,865) (12,562)
Accrued interest................................... (7,392) (12,412) 847 (3,568)
Other.............................................. (11,821) 42,698 (30,183) 30,728
--------- ---------- --------- ---------
Net cash provided from operating activities...... 1,311 124,454 161,101 129,274
--------- ---------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- -- 80,908 --
Short-term borrowings, net........................... 101,255 16,976 -- 50,221
Redemptions and Repayments-
Preferred Stock...................................... -- (93) -- (93)
Long-term debt....................................... (175) (100,962) (8,101) (146,065)
Short-term borrowings, net........................... -- -- (80,912) --
Dividend Payments-
Common stock......................................... (90,000) -- (145,000) --
Preferred stock...................................... (1,754) (1,865) (3,498) (3,730)
--------- ---------- --------- ---------
Net cash provided from (used for) financing
activities..................................... 9,326 (85,944) (156,603) (99,667)
--------- ---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (20,861) (30,805) (38,729) (62,023)
Loans payments from associated companies............... 13,736 220 10,814 220
Investments in lessor notes............................ -- -- 20,965 19,071
Contributions to nuclear decommissioning trusts........ (7,256) -- (14,512) (7,256)
Other.................................................. 3,744 (8,592) (7,618) (9,842)
--------- ---------- --------- ---------
Net cash used for investing activities........... (10,637) (39,177) (29,080) (59,830)
--------- ---------- --------- ---------
Net decrease in cash and cash equivalents................. -- (667) (24,582) (30,223)
Cash and cash equivalents at beginning of period.......... 200 826 24,782 30,382
--------- ---------- --------- ---------
Cash and cash equivalents at end of period................ $ 200 $ 159 $ 200 $ 159
========= ========== ========= =========
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.
78
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of
Directors of The Cleveland
Electric Illuminating Company:
We have reviewed the accompanying consolidated balance sheet of The Cleveland
Illuminating Electric Company and its subsidiaries as of June 30, 2004, and the
related consolidated statements of income and comprehensive income and cash
flows for each of the three-month and six-month periods ended June 30, 2004 and
2003. These interim financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 the standards of the Public Company
Accounting Oversight Board (United States), 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
August 6, 2004
79
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
some 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 second quarter of 2004 increased to
$48 million from $7 million in the second quarter of 2003. For the first six
months of 2004, earnings on common stock increased to $95 million from $66
million in the same period of 2003. Earnings on common stock in the first six
months 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 was $25 million in the first half of 2003. Increased
earnings in both 2004 periods resulted principally from higher operating
revenues and lower nuclear operating costs partially offset by higher other
operating costs compared to 2003. Revenues for both periods were higher due to
significant increases in wholesale sales. Lower nuclear operating costs in the
second quarter and the first six months of 2004, compared with the same periods
of 2003, were primarily due to the reduction in incremental costs associated
with the Davis-Besse extended outage and unplanned work performed during the
Perry Plant's nuclear refueling outage in the second quarter of 2003.
Operating revenues increased by $29 million or 7.0% in the second
quarter of 2004 from the same period of 2003. Higher revenues resulted
principally from a $43 million (65.3%) increase in wholesale sales (primarily to
FES) due to increased nuclear generation available for sale which was partially
offset by a 2.3% decrease in retail generation sales that reduced generation
sales revenue by $4 million. In the first six months of 2004, operating revenues
increased by $36 million (4.3%) primarily as a result of a $57 million increase
in wholesale sales revenues (primarily to FES) due to increased available
nuclear generation in the first half of 2004. The increase in wholesale sales
was partially offset by a 3.6% decrease in retail generation sales, which
resulted in lower revenues of $10 million. The reduction in retail generation
sales resulted from an increase in electric generation services provided by
alternative suppliers as a percent of total sales deliveries in CEI's franchise
area by 1.2 percentage points and 2.9 percentage points in the second quarter
and the first half of 2004, respectively, as compared to the same periods in
2003.
Distribution deliveries were nearly unchanged in the second quarter
of 2004 and increased 1.2% in the first six months of 2004 compared to the
corresponding periods of 2003. Commercial and industrial distribution deliveries
increased 0.6% and 1.4%, respectively, but were offset by a 4.7% reduction in
deliveries to residential customers resulting from moderate temperatures
affecting air conditioning demand in the second quarter of 2004. Lower revenues
of $3 million from electricity throughput in that period were due to lower unit
costs. In the first half of 2004, a 2.9% increase in distribution deliveries to
industrial customers reflected an improving economy; however, revenues from
electricity throughput decreased $5 million due to lower unit prices, which
offset the effect of higher volume.
Under the Ohio transition plan, CEI provides incentives to customers
to encourage switching to alternative energy providers - $7 million of
additional credits in the second quarter and $4 million of additional credits in
the first six months of 2004 compared with the corresponding periods of 2003.
The lower credit amount in the first six months of 2004 was due to decreased
credits in the first quarter of 2004 resulting from lower unit prices of the
shopping incentives offsetting increased shopping levels in that period. These
revenue reductions are deferred for future recovery under the transition plan
and do not materially affect current period earnings.
Changes in electric generation sales and distribution deliveries in
the second quarter and first six months of 2004 from the corresponding periods
of 2003 are summarized in the following table:
80
Changes in Kilowatt-hour Sales Three Months Six Months
--------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (2.3)% (3.6)%
Wholesale............................. 66.3% 35.8%
------------------------------------------------------------------
Total Electric Generation Sales......... 29.5% 15.0%
==================================================================
Distribution Deliveries:
Residential........................... (4.7)% (1.3)%
Commercial............................ 0.6% 0.8%
Industrial............................ 1.4% 2.9%
------------------------------------------------------------------
Total Distribution Deliveries (0.3)% 1.2%
==================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $4 million in the
second quarter and $17 million in the first six months of 2004 from the same
periods of 2003. The following table presents changes from the prior year by
expense category.
Operating Expenses and Taxes - Changes Three Months Six Months
---------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel.......................................... $ 9 $ 12
Purchased power............................... 5 4
Nuclear operating costs....................... (44) (72)
Other operating costs......................... 9 16
--------------------------------------------------------------------------
Total operation and maintenance expenses.... (21) (40)
Provision for depreciation and amortization... (3) 7
General taxes................................. (3) (4)
Income taxes.................................. 23 20
--------------------------------------------------------------------------
Total operating expenses and taxes.......... $ (4) $ (17)
==========================================================================
Higher fuel costs in the second quarter and first six months of 2004,
compared with the same periods of 2003, resulted from increased fossil and
nuclear generation. Higher purchased power costs reflect higher unit costs,
partially offset by lower kilowatt-hours purchased. Reductions in nuclear
operating costs for both periods were due to the reduction in incremental costs
associated with the Davis-Besse outage and unplanned work performed during the
Perry nuclear plant's 56-day refueling outage (44.85% ownership) in the second
quarter of 2003. The increase in other operating costs in the second quarter and
first six months of 2004, compared to the same periods of 2003, resulted
primarily from higher vegetation management costs.
The decrease in depreciation and amortization charges in the second
quarter of 2004, compared with the first quarter of 2003, was primarily due to
higher shopping incentive deferrals ($6 million) and shopping incentive carrying
charges (see Regulatory Matters) in the second quarter of 2004 ($7 million),
partially offset by increased amortization of regulatory assets ($10 million).
The increase in depreciation and amortization charges in the first six months of
2004, compared with the first six months of 2003 was primarily due to increased
amortization of regulatory assets ($16 million), partially offset by higher
shopping incentive deferrals ($4 million) and the shopping incentive carrying
charges ($7 million).
General taxes decreased in the second quarter and first six months of
2004, compared to the same period last year, primarily due to reduced property
taxes (including a $2 million refund received on a real estate valuation
settlement).
Other Income
Other income increased by $5 million in the second quarter and $12
million in the first six months of 2004, compared to the same period in 2003,
principally due to 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 $3
million in the second quarter and $10 million in the first six months of 2004
from the same periods last year, reflecting redemptions and refinancings since
the end of the second quarter of 2003. CEI's long-term debt redemptions of $8
million during the first six months 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
81
the existing decommissioning liabilities and ceasing the accounting practice of
depreciating non-regulated generation assets using a cost of removal component
was a $73 million increase to income, or $42 million net of income taxes.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements increased $2 million in the
first six months 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 two 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 June 30, 2004, CEI had $200,000 of cash and cash equivalents,
compared with $25 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 second quarter and
first six months of 2004, compared with the corresponding periods in 2003 were
as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -----------------
Operating Cash Flows 2004 2003 2004 2003
------------------------------------------------------------------------
(In millions)
Cash earnings (1)....... $ 107 $ 40 $179 $ 72
Working capital and other (106) 84 (18) 57
------------------------------------------------------------------------
Total ........... $ 1 $124 $161 $129
========================================================================
(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 decreased $123 million in
the second quarter of 2004 from the second quarter of 2003 as a result of a $190
million decrease from changes in working capital and other, partially offset by
a $67 million increase in cash earnings. The largest factor contributing to the
change in working capital was a decrease in accounts payable. Net cash provided
from operating activities increased $32 million in the first six months of 2004
compared to the same period last year as a result of a $107 million increase in
cash earnings, partially offset by a $75 million reduction from changes in
working capital - principally a decrease in accounts payable. The increase in
cash earnings reflects the favorable impact of reduced nuclear operating costs.
Cash Flows From Financing Activities
Net cash provided from financing activities increased $95 million in
the second quarter of 2004 from the second quarter of 2003. The increase in
funds provided from financing activities resulted from a decrease in net
redemptions of debt of $101 million and an $84 million net increase in
short-term borrowings, partially offset by a $90 million increase in common
stock dividends to FirstEnergy. Net cash used for financing activities increased
$57 million in the first six months of 2004 from the same period last year. The
increase was a result of $145 million increase in common stock dividends to
FirstEnergy partially offset by an $88 million reduction in net redemptions of
debt.
CEI had about $0.7 million of cash and temporary investments (which
include short-term notes receivable from associated companies) and approximately
$117 million of short-term indebtedness as of June 30, 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
82
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 second quarter of 2004 was 1.39%.
On June 15, 2004, $27.7 million Ohio Water Development Authority
Series 1999-A pollution control revenue refunding bonds were remarketed and
converted to a weekly interest rate mode, and a letter of credit in support of
principal and interest payments on the bonds was issued.
CEI's access to capital markets and costs of financing are dependent
on the ratings of its securities and that of FirstEnergy. On April 28, 2004,
Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that
FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed
credit facilities at the holding company level provided a substantial source of
liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened
the average maturity of its bank facilities and had made reductions to its total
consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility
through debt reduction and divestiture of non-core assets, FirstEnergy's
integrated regional strategy, and strong liquidity as credit strengths. Moody's
noted the substantial debt burden associated with the GPU merger, fully
competitive generating markets, and modest growth in markets served as credit
challenges for FirstEnergy. Moody's also noted that a "track record of improving
financial condition, especially a track record of debt reduction, could cause
the ratings to go up" and that the opposite development could cause the ratings
to go down.
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
Cash Flows From Investing Activities
In the second quarter and first six months of 2004, net cash used for
investing activities decreased $29 million and $31 million, respectively, from
the corresponding periods of 2003. The decrease in funds used for investing
activities primarily reflected lower capital expenditures and increased loan
payments from associated companies.
During the second half of 2004, capital requirements for property
additions are expected to be about $77 million, including $26 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 June 30, 2004, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $111
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 $117
million of off-balance sheet financing as of June 30, 2004.
As of June 30, 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 adoption of FIN 46R effective
December 31, 2003, but have subsequently been deconsolidated under FIN 46R (see
Note 2 - Consolidation). 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 $210
million and $188 million as of June 30, 2004 and December 31, 2003,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $21 million reduction in fair value as of June 30, 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.
83
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. Under the recently approved Rate Stabilization Plan, CEI has
continuing PLR responsibility to its franchise customers through December 31,
2008.
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
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 that proposal, CEI requested:
o Extension of the transition cost amortization period for
CEI from 2008 to 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 February 23, 2004, after consideration of the PUCO Staff comments
and testimony as well as those provided by some of the intervening parties, CEI
made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the
PUCO issued an order approving the revised Rate Stabilization Plan, subject to
conducting a competitive bid process on or before December 1, 2004. In addition
to requiring the competitive bid process, the PUCO made other modifications to
CEI's revised Rate Stabilization Plan application. Among the major modifications
were the following:
o Limiting the ability of CEI to request adjustments in
generation charges during 2006 through 2008 for increases
in taxes;
o Expanding the availability of market support generation;
o Revising the kilowatt-hour target level and the time
period for recovering regulatory transition charges;
o Establishing a 3-year competitive bid process for
generation;
o Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008;
and
o Denying the ability to defer costs for future recovery of
distribution reliability improvement expenditures.
84
On June 18, 2004, the CEI filed with the PUCO an application for
rehearing of the modified version of the Rate Stabilization Plan. Several other
parties also filed applications for rehearing. On August 4, 2004, the PUCO
issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications
included the following:
o Expanding CEI's ability to request adjustments in
generation charges during 2006 through 2008 to include
increases in the cost of fuel (including the cost of
emission allowances consumed, lime, stabilizers and other
additives and fuel disposal) using 2002 as the base year.
Any increases in fuel costs would be subject to downward
adjustments in subsequent years should fuel costs decline,
but not below the generation rate initially established in
the Rate Stabilization Plan;
o Approving the revised kilowatt-hour target level and time
period for recovery of regulatory transition costs as
presented by CEI in its rehearing application;
o Retaining the requirement for expanded availability of
market support generation, but adopting CEI's alternative
approach that conditions expanded availability on higher
pricing and eliminating the requirement to reduce the
interest deferral for certain affected rate schedules;
o Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules;
and
o Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances.
On August 5, 2004, CEI accepted the Rate Stabilization Plan as
modified and approved by the PUCO on August 4, 2004. CEI retains the right to
withdraw the modified Rate Stabilization Plan should subsequent adverse action
be taken by the PUCO or a court. In the second quarter of 2004, CEI implemented
the accounting modifications contained in the PUCO's June 9, 2004 Order, which
are consistent with the PUCO's August 4, 2004 Entry on Rehearing. Those
modifications included amortization of transition costs based on extended
amortization periods (that are no later than mid-2009 for CEI) and the deferral
of interest costs on the accumulated deferred shopping incentives.
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 June 30, 2004 and December 2003 were $1.0 billion and $1.1 billion,
respectively. All of CEI's regulatory assets are expected to continue to be
recovered under the provisions of the transition plan.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On February 26 and 27, 2004, CEI 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, was an
independent review to identify areas recommended for reliability improvement.
The final audit report was completed on May 6, 2004. The report identified
positive observations and included various recommendations for reliability
improvement. FirstEnergy implemented the audit results and recommendations
relating to summer 2004 and reported completion of those recommendations on June
30, 2004, with one exception related to MISO's implementation of a voltage
stability tool expected to be finalized later this year. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
85
On March 1, 2004, CEI filed, in accordance with a November 25, 2003
order from the PUCO, its 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 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
On April 22, 2004, FirstEnergy filed with the 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 2009. FirstEnergy is continuing to review
the results of that study related to 2009 and completed the implementation
of recommendations relating to 2004 by June 30, 2004. 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
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 believes it 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) were required to comply by May 31, 2004
with individual state NOx budgets. Pennsylvania submitted a SIP that required
compliance with the state NOx budgets at CEI's Pennsylvania facilities by May 1,
2003. Ohio submitted a SIP that required compliance with the state NOx budgets
at CEI's Ohio facilities by May 31, 2004. CEI believes its facilities are
complying with the state NOx budgets through combustion controls and
post-combustion controls, including Selective Catalytic Reduction and Selective
Non-Catalytic Reduction systems, and/or using emission allowances.
86
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 June 30, 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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives above). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Legal Matters
Various lawsuits, claims, including claims for asbestos exposure, 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. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004.
As part of its informal inquiry, which began in September 2003, the
SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy
voluntarily provide information and documents related to the Davis-Besse outage.
FirstEnergy is complying with this request and continues to cooperate fully with
this inquiry. 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.
FirstEnergy's Ohio utility subsidiaries were 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
87
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. 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 by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and post-retirement benefit obligations are
allocated to its subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. CEI'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 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. FirstEnergy reduced its assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
88
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
half 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.
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 initial 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 Rate Stabilization 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 judgment 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 FCON 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 most recent 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 June 30, 2004, CEI had $1.7 billion of goodwill.
89
New Accounting Standards And Interpretations
- --------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the
EITF on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. CEI does not
expect the adoption of EITF 03-1 to have a material impact on its consolidated
financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on the accounting for
the effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy
provided under the Medicare Act 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. See Note 2 - Consolidation for a
discussion of variable interest entities and the impact of the FIN 46
implementation on the financial statements of CEI.
90
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- -----------
Restated Restated
(See Note 2) (See Note 2)
(In thousands)
OPERATING REVENUES........................................ $ 243,366 $ 215,988 $ 478,764 $ 447,810
--------- ---------- --------- ---------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 13,073 6,148 23,287 14,554
Purchased power........................................ 74,687 74,225 157,095 148,476
Nuclear operating costs................................ 38,119 66,641 78,858 131,196
Other operating costs.................................. 39,202 33,306 77,363 66,238
Provision for depreciation and amortization............ 31,550 34,678 72,239 70,318
General taxes.......................................... 12,028 13,966 26,328 28,974
Income taxes (benefit)................................. 8,080 (11,099) 6,502 (15,390)
--------- ---------- --------- ---------
Total operating expenses and taxes................. 216,739 217,865 441,672 444,366
--------- ---------- --------- ---------
OPERATING INCOME (LOSS)................................... 26,627 (1,877) 37,092 3,444
OTHER INCOME.............................................. 4,719 3,776 10,552 6,876
NET INTEREST CHARGES:
Interest on long-term debt............................. 9,581 11,283 19,042 22,171
Allowance for borrowed funds used during construction.. (702) (1,184) (2,102) (2,490)
Other interest expense................................. 889 961 1,595 429
--------- ---------- --------- ---------
Net interest charges............................... 9,768 11,060 18,535 20,110
--------- ---------- --------- ---------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE...................................... 21,578 (9,161) 29,109 (9,790)
Cumulative effect of accounting change (net of income taxes
of $18,201,000) (Note 2)............................... -- -- -- 25,550
--------- ---------- --------- ---------
NET INCOME (LOSS)......................................... 21,578 (9,161) 29,109 15,760
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,211 2,211 4,422 4,416
--------- ---------- --------- ---------
EARNINGS (LOSS) ON COMMON STOCK........................... $ 19,367 $ (11,372) $ 24,687 $ 11,344
========= ========== ========= =========
COMPREHENSIVE INCOME:
NET INCOME (LOSS)......................................... $ 21,578 $ (9,161) $ 29,109 $ 15,760
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- 9,622 -- 9,622
Unrealized gain (loss) on available for sale securities (6,974) 15,367 (1,292) 14,481
--------- ---------- --------- ---------
Other comprehensive income (loss)......................... (6,974) 24,989 (1,292) 24,103
Income tax related to other comprehensive income....... 2,861 (10,018) 530 (9,655)
--------- ---------- --------- ---------
Other comprehensive income (loss), net of tax........ (4,113) 14,971 (762) 14,448
--------- ---------- --------- ---------
TOTAL COMPREHENSIVE INCOME................................ $ 17,465 $ 5,810 $ 28,347 $ 30,208
========= ========== ========= =========
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.
91
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service.................................................................... $1,810,342 $1,714,870
Less-Accumulated provision for depreciation................................... 748,218 721,754
---------- ----------
1,062,124 993,116
---------- ----------
Construction work in progress-
Electric plant.............................................................. 67,721 125,051
Nuclear fuel................................................................ -- 20,189
---------- ----------
67,721 145,240
---------- ----------
1,129,845 1,138,356
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes.................................................... 190,658 200,938
Nuclear plant decommissioning trusts.......................................... 259,644 240,634
Long-term notes receivable from associated companies.......................... 163,872 163,626
Other......................................................................... 2,133 2,119
---------- ----------
616,307 607,317
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents..................................................... 15 2,237
Receivables-
Customers................................................................... 5,873 4,083
Associated companies........................................................ 12,665 29,158
Other....................................................................... 3,614 14,386
Notes receivable from associated companies.................................... 19,727 19,316
Materials and supplies, at average cost....................................... 38,798 35,147
Prepayments and other........................................................ 1,410 6,704
---------- ----------
82,102 111,031
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................. 415,768 459,040
Goodwill...................................................................... 504,522 504,522
Property taxes................................................................ 24,443 24,443
Other......................................................................... 10,781 10,689
---------- ----------
955,514 998,694
---------- ----------
$2,783,768 $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...................................... 10,910 11,672
Retained earnings........................................................... 138,306 113,620
---------- ----------
Total common stockholder's equity......................................... 773,445 749,521
Preferred stock not subject to mandatory redemption........................... 126,000 126,000
Long-term debt................................................................ 274,133 270,072
---------- ----------
1,173,578 1,145,593
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.............................................. 335,950 283,650
Short-term borrowings......................................................... -- 70,000
Accounts payable-
Associated companies........................................................ 117,574 132,876
Other....................................................................... 2,348 2,816
Notes payable to associated companies......................................... 238,893 285,953
Accrued taxes................................................................ 59,339 55,604
Accrued interest.............................................................. 12,041 12,412
Lease market valuation liability.............................................. 24,600 24,600
Other......................................................................... 29,956 37,299
---------- ----------
820,701 905,210
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes............................................. 200,300 201,954
Accumulated deferred investment tax credits................................... 26,135 27,200
Retirement benefits........................................................... 50,415 47,006
Asset retirement obligation................................................... 187,974 181,839
Lease market valuation liability.............................................. 280,300 292,600
Other......................................................................... 44,365 53,996
---------- ----------
789,489 804,595
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)...............................
---------- ----------
$2,783,768 $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.
92
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ -----------------------
2004 2003 2004 2003
---------- ---------- ---------- -----------
Restated Restated
(See Note 2) (See Note 2)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 21,578 $ (9,161) $ 29,109 $ 15,760
Adjustments to reconcile net income (loss) to net
cash from operating activities-
Provision for depreciation and amortization........ 31,550 34,678 72,239 70,318
Nuclear fuel and capital lease amortization........ 5,032 1,820 10,538 4,588
Deferred operating lease costs, net................ (28,582) (27,788) (36,274) (35,460)
Deferred income taxes, net......................... (2,118) (2,138) (3,617) 16,992
Amortization of investment tax credits............. (533) (514) (1,065) (1,028)
Accrued retirement benefit obligation.............. 1,124 (17,217) 3,409 (16,446)
Accrued compensation, net.......................... 1,694 (824) 961 (2,689)
Cumulative effect of accounting change (Note 2).... -- -- -- (43,751)
Receivables........................................ 5,440 (74,711) 25,475 (62,462)
Materials and supplies............................. (2,217) 5,877 (3,651) 5,150
Prepayments and other current assets............... 1,910 (3,858) 5,294 (8,979)
Accounts payable................................... (9,696) 42,068 (15,770) (11,849)
Accrued taxes...................................... 17,820 (4,880) 3,735 1,401
Accrued interest................................... 1,910 2,200 (371) (126)
Other.............................................. 5,000 69,964 5,080 54,526
-------- --------- --------- --------
Net cash provided from (used for) operating activities 49,912 15,516 95,092 (14,055)
-------- --------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- -- 73,000 --
Short-term borrowings, net........................... -- 33,199 -- 131,591
Redemptions and Repayments-
Long-term debt....................................... -- (9,162) (15,000) (82,762)
Short-term borrowings, net........................... (23,761) -- (117,060) --
Dividend Payments-
Preferred stock...................................... (2,211) (2,211) (4,422) (4,422)
-------- --------- --------- --------
Net cash provided from (used for) financing activities (25,972) 21,826 (63,482) 44,407
-------- --------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (10,987) (18,126) (19,427) (35,748)
Loans to associated companies.......................... (3,263) (4,294) (657) (8,739)
Investment in lessor notes............................. -- (38) 10,280 17,590
Contributions to nuclear decommissioning trust......... (7,136) -- (14,271) (7,135)
Other.................................................. (2,555) (6,020) (9,757) (6,699)
-------- --------- --------- --------
Net cash used for investing activities........... (23,941) (28,478) (33,832) (40,731)
-------- --------- --------- --------
Net increase (decrease) in cash and cash equivalents...... (1) 8,864 (2,222) (10,379)
Cash and cash equivalents at beginning of period.......... 16 1,445 2,237 20,688
-------- --------- --------- --------
Cash and cash equivalents at end of period................ $ 15 $ 10,309 $ 15 $ 10,309
======== ========= ========= ========
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.
93
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and six-month periods ended June 30, 2004 and 2003.
These interim financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 and six-month periods ended June 30, 2003.
We previously audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), 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 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
August 6, 2004
94
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
some 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 second quarter and first six months 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 $0.6 million ($0.3 million
after tax) and $1.0 million ($0.6 million after tax) in the second quarter and
the first six months of 2003, respectively. In addition, TE's interest expense
was overstated by $0.3 million ($0.2 million after tax) and $1.3 million ($0.7
million after tax) in the second quarter and the first six months of 2003,
respectively. 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 second quarter of 2004 increased to
$19 million from a loss of $11 million in the second quarter of 2003. Earnings
on common stock in the first six months of 2004 increased to $25 million from
$11 million in the first six months of 2003. The results for the six-month
period in 2003 included an after-tax credit of $26 million from the cumulative
effect of an accounting change due to the adoption of SFAS 143. The loss before
the cumulative effect was $10 million in the first half of 2003. Increased
earnings in both 2004 periods resulted principally from higher operating
revenues and lower nuclear operating costs compared to 2003.
Operating revenues increased by $28 million, or 12.7%, in the second
quarter and by $31 million, or 6.9%, in the first six months of 2004 compared to
the same periods in 2003. Higher revenues resulted from additional wholesale
sales to FES due to increased generation available for sale. Wholesale sales
increased 96% in the second quarter and 57% in the first half of 2004 from the
same periods in 2003. Higher fossil generation at the Mansfield Plant and the
return to service of Davis-Besse on April 4, 2004 increased generation available
for sale in the second quarter of 2004.
Increased wholesale sales in the second quarter and first six months
of 2004 compared to the same periods of 2003 were partially offset by lower
retail generation sales. Revenues from retail generation sales in the second
quarter and first six months of 2004 decreased $5 million and $8 million,
respectively, as kilowatt-hour sales of electricity by alternative suppliers in
TE's franchise area increased by 1.7 percentage points in the second quarter and
first half of 2004. TE's retail generation sales decreased 5.4% in the second
quarter and 4.7% in the first six months of 2004 compared to the corresponding
periods of 2003.
Distribution deliveries decreased 3.3% in the second quarter of 2004
compared to the same period last year as a reduction in residential and
industrial deliveries more than offset an increase in the commercial customer
sector. A $3 million decrease in revenues from electricity throughput in the
second quarter of 2004 from the same quarter last year was due to reduced
distribution deliveries partially offset by higher composite prices.
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 reduction in revenues from shopping credits
was approximately $1 million less in both the second quarter and first six
months of 2004 when compared with the reductions in the corresponding periods of
2003.
Changes in electric generation sales and distribution deliveries in
the second quarter and first six months of 2004 from the corresponding periods
of 2003 are summarized in the following table:
95
Changes in Kilowatt-Hour Sales Three Months Six Months
--------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (5.4)% (4.7)%
Wholesale............................. 95.9% 57.0%
------------------------------------------------------------------
Total Electric Generation Sales......... 35.0% 20.1%
==================================================================
Distribution Deliveries:
Residential........................... (4.9)% (5.0)%
Commercial............................ 2.3% (0.9)%
Industrial............................ (5.3)% (2.2)%
-------------------------------------------------------------------
Total Distribution Deliveries........... (3.3)% (2.5)%
===================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $1 million in the
second quarter and by $3 million in the first six months of 2004 from the same
periods in 2003. The following table presents changes from the prior year by
expense category.
Operating Expenses and Taxes - Changes Three Months Six Months
----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel........................................... $ 7 $ 9
Purchased power costs.......................... -- 8
Nuclear operating costs........................ (29) (52)
Other operating costs.......................... 7 11
----------------------------------------------------------------------------
Total operation and maintenance expenses..... (15) (24)
Provision for depreciation and amortization.... (3) 2
General taxes.................................. (2) (3)
Income taxes................................... 19 22
----------------------------------------------------------------------------
Net decrease in operating expenses and taxes. $ (1) $ (3)
============================================================================
Higher fuel costs in the second quarter of 2004, compared with the
second quarter of 2003, resulted primarily from increased nuclear generation as
a result of Davis-Besse's return to full service on April 4, 2004. Higher
purchased power costs in the first six months of 2004, compared to the same
period last year, reflect higher unit costs, partially offset by lower
kilowatt-hours purchased due to reduced retail generation demand.
Lower nuclear operating costs in the second quarter and the first six
months of 2004, compared to the same periods of 2003, were primarily due to the
absence of incremental costs in the second quarter and lower incremental costs
in the first six months of 2004 associated with the Davis-Besse Plant
restoration outage. Nuclear operating costs were also lower in the second
quarter of 2004 as a result of no nuclear refueling outages compared to a 56-day
refueling outage at the Perry Plant (19.91% ownership) in the second quarter of
2003.
The increase in other operating costs in the second quarter and first
six months of 2004, compared to the same periods of 2003, was due in part to
higher vegetation management costs.
Depreciation and amortization decreased by $3 million in the second
quarter of 2004, compared with the second quarter of 2003, primarily due to
higher shopping incentive deferrals ($1 million) and the deferral of interest
costs on shopping incentives ($2 million). The interest deferrals were
implemented in the second quarter of 2004 (retroactive to January 1, 2004)
pursuant to the Ohio Rate Stabilization Plan. The increase in depreciation and
amortization charges of $2 million in the first six months of 2004, compared
with the first six months of 2003, was primarily due to the increased
amortization of regulatory assets ($4 million), partially offset by higher
shopping incentive deferrals ($1 million) and the deferral of interest costs on
accumulated deferred shopping incentives ($2 million).
Other Income
Other income increased by $4 million in the first six months of 2004
compared to the same period of 2003, due primarily to the absence of 2003 costs
related to closing the Acme power plant in Toledo, Ohio.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $1
million in the second quarter of 2004 and $2 million in the first six months of
2004 from the same periods of 2003, reflecting redemptions and refinancings
since June 30, 2003. TE's long-term debt redemptions of $15 million during the
first six months of 2004 and its repricing of $54 million of pollution control
notes in the second quarter of 2004 are expected to result in annualized savings
of approximately $1 million.
96
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 two 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 June 30, 2004, TE had approximately $15,000 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 by (used for) operating activities during the second
quarter and first six months of 2004 and corresponding periods in 2003 were as
follows:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------
Operating Cash Flows 2004 2003 2004 2003
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $30 $(21) $75 $ 8
Working capital and other 20 37 20 (22)
------------------------------------------------------------------------
Total.................... $50 $ 16 $95 $(14)
========================================================================
(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 $34 million in
the second quarter of 2004 from the second quarter of 2003 resulting from a $51
million increase in cash earnings partially offset by a $17 million decrease
from changes in working capital. The increase in cash earnings was primarily due
to higher operating revenues and lower nuclear operating costs. The largest
factors contributing to the change in working capital were decreases in payables
and other current liabilities partially offset by a decrease in receivables.
Net cash provided from operating activities increased $109 million in
the first six months of 2004 from the first six months of 2003 as a result of a
$67 million increase in cash earnings and a $42 million increase from changes in
working capital. The change in working capital reflects lower receivables. 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. Higher operating revenues and lower
nuclear costs contributed to the increase in cash earnings in the first half of
2004.
Cash Flows From Financing Activities
Net cash used for financing activities was $26 million in the second
quarter of 2004 compared to $22 million provided from financing activities in
the second quarter of 2003. The change was primarily due to increased repayments
on short-term borrowings.
Net cash used for financing activities was $63 million in the first
six months of 2004 compared to $44 million provided from financing activities in
the first six months of 2003. Repayments and redemptions of debt in the first
six months of 2004 exceeded proceeds from issuing new long-term debt by $59
million. In the first six months of 2003, short-term borrowings exceeded
repayments of long-term debt by $49 million.
As of June 30, 2004, TE had $20 million of cash and temporary
investments (which include short-term notes receivable from associated
companies) and $239 million of short-term indebtedness. TE is currently
precluded from issuing FMB or preferred stock based upon applicable earnings
coverage tests.
97
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 second quarter of 2004 was 1.39%.
On June 1, 2004, $34.85 million Beaver County Industrial Development
Authority Series 1999-A pollution control revenue refunding bonds were
remarketed and converted to a weekly interest rate mode, and a letter of credit
in support of principal and interest payments on the bonds was issued.
On June 15, 2004, $18.8 million Ohio Water Development Authority
Series 1999-A pollution control revenue refunding bonds were remarketed and
converted to a weekly interest rate mode, and a letter of credit in support of
principal and interest payments on the bonds was issued.
TE's access to capital markets and costs of financing are dependent on
the ratings of its securities and that of its holding company, FirstEnergy. The
ratings outlook on all of its securities is stable.
On April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted that, in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility via
debt reduction and divestiture of non-core assets, FirstEnergy's integrated
regional strategy, and strong liquidity as credit strengths. Moody's noted the
substantial debt burden associated with the GPU merger, fully competitive
generating markets, and modest growth in markets served as credit challenges for
FirstEnergy. Moody's also noted that a "track record of improving financial
condition, especially a track record of debt reduction, could cause the ratings
to go up" and that the opposite development could cause the ratings to go down.
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
Cash Flows From Investing Activities
Net cash used for investing activities decreased $5 million in the
second quarter and $7 million in the first six months of 2004 when compared to
the same periods of 2003 and was primarily due to lower capital expenditures in
both periods.
During the last two quarters of 2004, capital requirements for
property additions are expected to be about $27 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
borrowings.
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 June 30, 2004, the present value of these sale
and leaseback operating lease commitments, net of trust investments, total $561
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 $61 million of
off-balance sheet financing as of June 30, 2004.
Equity Price Risk
- -----------------
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $163
million and $145 million as of June 30, 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 June 30, 2004.
98
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 were restructured into separate components to support customer
choice. Under the recently approved Rate Stabilization Plan, TE has continuing
PLR responsibility to its franchise customers through December 31, 2008.
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. Under the recently approved Rate Stabilization Plan, TE has continuing
PLR responsibility to its franchise customers through December 31, 2008.
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 MW of low cost supply to unaffiliated alternative suppliers who
serve customers within its service area. FES acts as an alternate supplier for a
portion of the load in TE's 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 that proposal, TE requested:
o Extension of the transition cost amortization period TE from
mid-2007 to 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 February 23, 2004, after consideration of the PUCO Staff comments
and testimony as well as those provided by some of the intervening parties, TE
made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the
PUCO issued an order approving the revised Rate Stabilization Plan, subject to
conducting a competitive bid process on or before December 1, 2004. In addition
to requiring the competitive bid process, the PUCO made other modifications to
TE's revised Rate Stabilization Plan application. Among the major modifications
were the following:
o Limiting the ability of TE to request adjustments in
generation charges during 2006 through 2008 for increases in
taxes;
o Expanding the availability of market support generation;
o Revising the kilowatt-hour target level and the time period
for recovering regulatory transition charges;
o Establishing a 3-year competitive bid process for
generation;
o Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008;
and
o Denying the ability to defer costs for future recovery of
distribution reliability improvement expenditures.
99
On June 18, 2004, TE filed with the PUCO an application for rehearing
of the modified version of the Rate Stabilization Plan. Several other parties
also filed applications for rehearing. On August 4, 2004, the PUCO issued an
Entry on Rehearing modifying its June 9, 2004 Order. The modifications included
the following:
o Expanding TE's ability to request adjustments in generation
charges during 2006 through 2008 to include increases in the
cost of fuel (including the cost of emission allowances
consumed, lime, stabilizers and other additives and fuel
disposal) using 2002 as the base year. Any increases in fuel
costs would be subject to downward adjustments in subsequent
years should fuel costs decline, but not below the
generation rate initially established in the Rate
Stabilization Plan;
o Approving the revised kilowatt-hour target level and time
period for recovery of regulatory transition costs as
presented by TE in its rehearing application;
o Retaining the requirement for expanded availability of
market support generation, but adopting TE's alternative
approach that conditions expanded availability on higher
pricing and eliminating the requirement to reduce the
interest deferral for certain affected rate schedules;
o Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and
o Relaxing the notice requirement for availability of enhanced
shopping credits in a number of instances.
On August 5, 2004, TE accepted the Rate Stabilization Plan as modified
and approved by the PUCO on August 4, 2004. TE retains the right to withdraw the
modified Rate Stabilization Plan should subsequent adverse action be taken by
the PUCO or a court. In the second quarter of 2004, TE implemented the
accounting modifications contained in the PUCO's June 9, 2004 Order, which are
consistent with the PUCO's August 4, 2004 Entry on Rehearing. Those
modifications included amortization of transition costs based on extended
amortization periods (that are no later than mid-2008 for TE) and the deferral
of interest costs on the accumulated deferred shopping incentives.
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 June 30, 2004 and December 2003 were $416 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.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On February 26 and 27, 2004, TE 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, was an
independent review to identify areas recommended for reliability improvement.
The final audit report was completed on May 6, 2004. The report identified
positive observations and included various recommendations for reliability
improvement. FirstEnergy implemented the audit results and recommendations
relating to summer 2004 and reported completion of those recommendations on June
30, 2004, with one exception related to MISO's implementation of a voltage
stability tool expected to be finalized later this year. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
100
On March 1, 2004, TE filed, in accordance with a November 25, 2003
order from the PUCO, its 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 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
On April 22, 2004, FirstEnergy filed with the 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 2009. FirstEnergy is continuing to review
the results of that study related to 2009 and completed the implementation
of recommendations relating to 2004 by June 30, 2004. 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
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 believes it 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) were required to comply by May 31, 2004 with
individual state NOx budgets. Pennsylvania submitted a SIP that required
compliance with the state NOx budgets at TE's Pennsylvania facilities by May 1,
2003. Ohio submitted a SIP that requires compliance with the state NOx budgets
at TE's Ohio facilities by May 31, 2004. TE believes its facilities are
complying with the state NOx budgets through combustion controls and
post-combustion controls, including Selective Catalytic Reduction and Selective
Non-Catalytic Reduction systems, and/or using emission allowances.
101
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
approximately $0.2 million as of June 30, 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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives above). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Legal Matters
Various lawsuits, claims, including claims for asbestos exposure, 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. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004.
As part of its informal inquiry, which began in September 2003, the
SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy
voluntarily provide information and documents related to the Davis-Besse outage.
FirstEnergy is complying with this request and continues to cooperate fully with
this inquiry. 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.
FirstEnergy's Ohio utility subsidiaries were 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
102
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.
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. 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 by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and postretirement benefit obligations are
allocated to subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. TE'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 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. FirstEnergy reduced its assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
103
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
half 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.
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 initial 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 Rate Stabilization 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 judgment 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 FCON 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 most recent 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 June 30, 2004,
TE had $505 million of goodwill.
104
New Accounting Standards And Interpretations
- --------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary
and Its Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the EITF
on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. TE does not
expect the adoption of EITF 03-1 to have a material impact on its consolidated
financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on accounting for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy
provided under the Medicare Act 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. See Note 2 - Consolidation for a
discussion of variable interest entities and the impact of the FIN 46
implementation on the financial statements of TE.
105
PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2004 2003 2004 2003
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $134,615 $116,559 $277,238 $244,902
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 5,855 4,218 12,061 8,931
Purchased power........................................ 44,095 36,954 92,603 81,020
Nuclear operating costs................................ 18,239 35,428 35,803 82,357
Other operating costs.................................. 14,415 10,060 29,159 26,610
Provision for depreciation and amortization............ 13,499 13,480 26,937 26,745
General taxes.......................................... 4,488 5,879 11,122 12,058
Income taxes........................................... 14,846 4,268 29,884 2,789
-------- -------- -------- --------
Total operating expenses and taxes................. 115,437 110,287 237,569 240,510
-------- -------- -------- --------
OPERATING INCOME.......................................... 19,178 6,272 39,669 4,392
OTHER INCOME.............................................. 560 563 1,542 1,124
NET INTEREST CHARGES:
Interest expense....................................... 2,798 4,112 5,523 8,176
Allowance for borrowed funds used during construction.. (1,004) (699) (1,926) (1,328)
-------- -------- -------- --------
Net interest charges............................... 1,794 3,413 3,597 6,848
-------- -------- -------- --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE...................................... 17,944 3,422 37,614 (1,332)
Cumulative effect of accounting change (net of income
taxes of $7,532,000) (Note 2)........................... -- -- -- 10,618
-------- -------- -------- --------
NET INCOME................................................ 17,944 3,422 37,614 9,286
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 640 911 1,280 1,823
-------- -------- -------- --------
EARNINGS ON COMMON STOCK.................................. $ 17,304 $ 2,511 $ 36,334 $ 7,463
======== ======== ======== ========
COMPREHENSIVE INCOME:
NET INCOME................................................ $ 17,944 $ 3,422 $ 37,614 $ 9,286
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- (20,956) -- (20,956)
Income tax related to other comprehensive income....... -- 8,629 -- 8,629
-------- -------- -------- --------
Other comprehensive income (loss), net of tax........ -- (12,327) -- (12,327)
-------- -------- -------- --------
TOTAL COMPREHENSIVE INCOME (LOSS)......................... $ 17,944 $ (8,905) $ 37,614 $ (3,041)
======== ======== ======== ========
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral
part of these statements.
106
PENNSYLVANIA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- -------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................... $827,317 $808,637
Less-Accumulated provision for depreciation.................... 340,240 324,710
-------- --------
487,077 483,927
-------- --------
Construction work in progress-
Electric plant.............................................. 80,154 68,091
Nuclear fuel................................................ 360 360
-------- --------
80,514 68,451
-------- --------
567,591 552,378
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts .......................... 135,504 133,867
Long-term notes receivable from associated companies........... 33,152 39,179
Other.......................................................... 721 2,195
-------- --------
169,377 175,241
-------- --------
CURRENT ASSETS:
Cash and cash equivalents...................................... 38 40
Notes receivable from associated companies..................... 415 399
Receivables-
Customers (less accumulated provisions of $828,000
and $769,000, respectively,for uncollectible accounts).... 43,845 44,861
Associated companies........................................ 6,096 24,965
Other....................................................... 1,198 1,047
Materials and supplies, at average cost........................ 36,214 33,918
Prepayments.................................................... 17,524 9,383
-------- --------
105,330 114,613
-------- --------
DEFERRED CHARGES:
Regulatory assets.............................................. 7,802 27,513
Other.......................................................... 8,888 9,634
-------- --------
16,690 37,147
-------- --------
$858,988 $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........................................... 67,513 54,179
-------- --------
Total common stockholder's equity....................... 244,120 230,786
Preferred stock not subject to mandatory redemption............ 39,105 39,105
Long-term debt and other long-term obligations................. 129,917 130,358
-------- --------
413,142 400,249
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt............................... 52,224 93,474
Accounts payable-
Associated companies........................................ 21,399 40,172
Other....................................................... 1,439 1,294
Notes payable to associated companies.......................... 33,537 11,334
Accrued taxes.................................................. 31,877 27,091
Other.......................................................... 12,345 12,840
-------- --------
152,821 186,205
-------- --------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................. 91,208 97,871
Accumulated deferred investment tax credits.................... 3,369 3,516
Asset retirement obligation.................................... 133,844 129,546
Retirement benefits............................................ 56,668 54,057
Other.......................................................... 7,936 7,935
-------- --------
293,025 292,925
-------- --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3).............
-------- --------
$858,988 $879,379
======== ========
The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Power Company are an integral part of these balance sheets.
107
PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2004 2003 2004 2003
-------- -------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 17,944 $ 3,422 $ 37,614 $ 9,286
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 13,499 13,480 26,937 26,745
Nuclear fuel and lease amortization................ 4,431 3,206 8,996 6,789
Deferred income taxes, net......................... 19 (2,368) (1,212) 3,754
Amortization of investment tax credits............. (564) (608) (1,139) (1,228)
Cumulative effect of accounting change (Note 2).... -- -- -- (18,150)
Receivables........................................ 19,948 4,278 19,734 21,540
Materials and supplies............................. (1,221) (89) (2,296) (520)
Prepayments and other current assets............... 5,192 3,810 (8,141) (12,478)
Accounts payable................................... (22,368) (30,005) (18,628) (2,161)
Accrued taxes...................................... (4,023) 4,530 4,786 8,801
Accrued interest................................... 527 2,033 (1,429) 24
Other.............................................. 1,084 422 3,941 571
-------- -------- -------- --------
Net cash provided from operating activities...... 34,468 2,111 69,163 42,973
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net........................... -- -- 22,203 --
Redemptions and Repayments-
Long-term debt....................................... (487) (601) (42,789) (617)
Short-term borrowings, net........................... (6,881) -- -- --
Dividend Payments-
Common stock......................................... (15,000) (13,000) (23,000) (26,000)
Preferred stock...................................... (640) (911) (1,280) (1,823)
-------- -------- -------- --------
Net cash used for financing activities........... (23,008) (14,512) (44,866) (28,440)
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (17,412) (9,680) (31,410) (40,734)
Contributions to nuclear decommissioning trusts........ (398) -- (797) (399)
Loan repayments from associated companies, net......... 6,127 19,692 6,011 24,613
Other.................................................. 221 603 1,897 806
-------- -------- -------- --------
Net cash provided from (used for) investing
activities ..................................... (11,462) 10,615 (24,299) (15,714)
-------- -------- -------- --------
Net decrease in cash and cash equivalents................. (2) (1,786) (2) (1,181)
Cash and cash equivalents at beginning of period.......... 40 1,827 40 1,222
-------- -------- -------- --------
Cash and cash equivalents at end of period................ $ 38 $ 41 $ 38 $ 41
======== ======== ======== ========
The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Power Company are an integral part of these statements.
108
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and six-month periods ended June 30, 2004 and 2003.
These interim financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 the standards of the Public Company
Accounting Oversight Board (United States), the balance sheet and the statement
of capitalization as of December 31, 2003, and the related statements of income,
common stockholder's equity, preferred stock, cash flows and taxes for the year
then ended (not presented herein), and in our report (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 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
August 6, 2004
109
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 second quarter of 2004 increased to
$17 million from $3 million in the second quarter of 2003. In the first six
months of 2004, earnings on common stock increased to $36 million from $7
million in the same period of 2003. Earnings in the first half 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. The loss before the cumulative effect
was $1 million for the first six months of 2003. Improved results in both
periods of 2004 resulted from higher operating revenues, lower nuclear operating
costs and reduced net interest charges.
Operating revenues increased $18 million, or 15.5%, in the second
quarter and $32 million, or 13.2%, in the first six months of 2004 compared with
the same periods in 2003. These increases reflect higher sales revenues of $19
million and $33 million in both periods of 2004 primarily resulting from
increased wholesale revenues of $13 million and $25 million, respectively, due
to increased nuclear generation available for sale to FES. Retail sales revenues
increased $6 million and $8 million in the second quarter and first six months
of 2004 as compared to the same periods of 2003, respectively, primarily due to
a 14.5% and 8.1% increase in generation sales, respectively. Warmer weather in
the second quarter of 2004 compared to the same quarter of 2003 and an improving
economy were major factors for the increase in generation sales in the second
quarter and first half of 2004.
Distribution deliveries increased 14.5% in the second quarter and 8.1%
in the first six months of 2004 compared with the same periods in 2003, with
increases in all customer sectors (residential, commercial and industrial) as a
result of the same factors discussed above. Higher deliveries to the steel
sector in the first half of 2004 are reflected in the significant increase in
kilowatt-hour sales to industrial customers. The changes in revenues from
electricity throughput were relatively flat for both periods with the effect of
the volume increases offset by lower composite prices.
Changes in electric generation sales and distribution deliveries in
the second quarter and first six months of 2004 from the same periods of 2003
are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Six Months
------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail............................. 14.5% 8.1%
Wholesale.......................... 44.6% 38.1%
----------------------------------------------------------------
Total Electric Generation Sales....... 31.3% 24.3%
================================================================
Distribution Deliveries:
Residential........................ 5.1% 3.8%
Commercial......................... 5.2% 2.7%
Industrial......................... 29.3% 17.1%
----------------------------------------------------------------
Total Distribution Deliveries......... 14.5% 8.1%
================================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased by $5 million in the
second quarter of 2004 from the second quarter of 2003 and decreased by $3
million in the first half of 2004 from the first half of 2003. The following
table presents changes from the prior year by expense category.
110
Operating Expenses and Taxes - Changes Three Months Six Months
-------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel......................................... $ 2 $ 3
Purchased power costs........................ 7 12
Nuclear operating costs...................... (17) (47)
Other operating costs........................ 4 3
----------------------------------------------------------------------
Total operation and maintenance expenses.. (4) (29)
Provision for depreciation and amortization.. -- --
General taxes................................ (1) (1)
Income taxes................................. 10 27
----------------------------------------------------------------------
Net change in operating expenses and taxes $ 5 $ ( 3)
=======================================================================
Higher fuel costs in the second quarter and first half of 2004,
compared with the same periods of 2003, resulted from increased nuclear
generation. Purchased power costs were higher in both periods of 2004 reflecting
increases in kilowatt-hour purchases and higher unit costs. The kilowatt-hour
purchases in the second quarter and the first half of 2004 increased to meet the
higher retail generation demand in both periods. Lower nuclear operating costs
occurred, in large part, due to the absence in 2004 of refueling outages at
Beaver Valley Unit 1 and Perry. Beaver Valley Unit 1 (65.00% ownership) and
Perry (5.24% ownership) experienced refueling outages in the first and second
quarters of 2003, respectively. Other operating costs increased in both periods
of 2004 due in part to increased employee benefit costs.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
approximately $2 million and $3 million in the second quarter and first half of
2004, respectively, from the same periods last year, reflecting mandatory and
optional debt redemptions of $83 million since June 30, 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 two years,
Penn expects to meet its contractual obligations with cash from operations.
Thereafter, Penn expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of June 30, 2004, Penn had $38,000 of cash and cash equivalents,
compared with $40,000 as of December 31, 2003. The major sources for changes in
these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities during the second
quarter and first six months of 2004, compared with the corresponding periods in
2003, were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------
Operating Cash Flows 2004 2003 2004 2003
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $36 $16 $74 $27
Working capital and other (2) (14) (5) 16
------------------------------------------------------------------------
Total ............ $34 $ 2 $69 $43
========================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
111
Net cash from operating activities increased $32 million in the second
quarter of 2004 compared to the same quarter of 2003 primarily due to a $20
million increase in cash earnings. During the first half of 2004, net cash from
operating activities increased $26 million due to a $47 million increase in cash
earnings partially offset by a $21 million decrease from changes in working
capital (primarily reduced accounts payable to associated companies). The
increases in cash earnings for both periods of 2004 were primarily due to the
combination of higher revenues and lower nuclear operating costs.
Cash Flows From Financing Activities
In the second quarter of 2004, net cash used for financing activities
increased to $23 million from $15 million in the same period last year. The
increase resulted from the repayment of short-term borrowings and increased
common stock dividends to OE. In the first half of 2004, net cash used for
financing activities increased to $45 million from $28 million in the same
period last year. The change resulted from increased long-term debt redemptions,
partially offset by increased short-term borrowings and reduced common stock
dividends to OE.
Penn had $453,000 of cash and temporary investments (which include
short-term notes receivable from associated companies) and $34 million of
short-term indebtedness as of June 30, 2004. Penn had the capability to issue
$460 million of additional FMB on the basis of property additions and retired
bonds. Based upon applicable earnings coverage tests, Penn could issue up to
$560 million of preferred stock (assuming no additional debt was issued) as of
June 30, 2004.
Penn 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 second quarter of 2004 was 1.39%.
In March 2004, Penn completed a receivables financing arrangement that
provides borrowing capability of 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 June 30,
2004 and matures on March 29, 2005.
On July 1, 2004, $14.5 million Ohio Air Quality Development Authority
Series 2002-A pollution control revenue refunding bonds were remarketed in an
annual interest rate mode.
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 April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted that, in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility via
debt reduction and divestiture of non-core assets, and FirstEnergy's integrated
regional strategy, and strong liquidity as credit strengths. Moody's noted the
substantial debt burden associated with the GPU merger, fully competitive
generating markets, and modest growth in markets served as credit challenges for
FirstEnergy. Moody's also noted that a "track record of improving financial
condition, especially a track record of debt reduction, could cause the ratings
to go up" and that the opposite development could cause the ratings to go down.
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in
response to changes in the industry. As a result of its revised methodology for
evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility
companies including JCP&L and Penn. Penn's FMB credit rating was upgraded to BBB
from BBB-.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $11 million in the
second quarter of 2004 compared to $11 million provided from investing
activities in the same quarter of 2003. The $22 million change reflects an
112
increase in capital expenditures and a decrease in loan repayments from
associated companies. For the first six months of 2004, net cash used for
investing activities was $24 million compared to $16 million in the same period
of 2003. The $8 million increase was due to reduced loan repayments from
associated companies - partially offset by lower capital expenditures.
During the second half of 2004, capital requirements for property
additions and capital leases are expected to be about $51 million, including $19
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 $53
million and $50 million as of June 30, 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 June 30, 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.
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 $8 million and $28
million as of June 30, 2004 and December 31, 2003, respectively.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On April 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
113
With respect to each of the foregoing initiatives, FirstEnergy
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 required additional reporting
on reliability. The PPUC ordered all Pennsylvania utilities to begin filing
quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
approving the revised reliability benchmark and standards, including revised
benchmarks and standards for Penn. The Order permitted Pennsylvania utilities to
file in a separate proceeding to revise the recomputed benchmarks and standards
if they have evidence, such as the impact of automated outage management
systems, on the accuracy of the PPUC computed reliability indices. Penn filed a
Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking
amendment of the benchmarks and standards due to their implementation of
automated outage management systems following restructuring. No procedural
schedule or hearing date has been set for this proceeding. Penn is unable to
predict the outcome of this proceeding.
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 was
filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and
Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held
in early August 2004 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 the end of 2004. Penn is unable to predict the outcome of the
investigation or the impact of the PPUC order.
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 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. These cases are referred to as New Source Review
cases. 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 trial to address civil penalties and what, if any,
actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated, in its August 2003
ruling, 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. While the parties are engaged in meaningful settlement
114
discussions, management is unable to predict the ultimate outcome of this matter
and no liability has been accrued as of June 30, 2004.
Penn believes it 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) were required to comply by May 31, 2004
with individual state NOx budgets. Pennsylvania submitted a SIP that required
compliance with the state NOx budgets at Penn's Pennsylvania facilities by May
1, 2003. Ohio submitted a SIP that required compliance with the state budgets at
Penn's Ohio facilities by May 31, 2004. Penn believes its facilities are
complying with the state NOx budgets through combustion controls and
post-combustion controls, including Selective Catalytic Reduction and Selective
Non-Catalytic Reduction systems, and/or using emission allowances.
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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives above). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Legal Matters
Various lawsuits, claims, including claims for asbestos exposure, 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 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 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.
115
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 by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and post-retirement benefit obligations are
allocated to its subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. Penn'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 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. FirstEnergy reduced its 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
half 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.
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
116
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 judgment 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 FCON 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
- --------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the EITF
on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. Penn does not
expect the adoption of EITF 03-1 to have a material impact on its consolidated
financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on the accounting for
the effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy
provided under the Medicare Act on the consolidated financial statements.
117
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2004 2003 2004 2003
-------- --------- ---------- ----------
Restated Restated
(See Note 2) (See Note 2)
(In thousands)
OPERATING REVENUES........................................ $549,665 $ 542,771 $1,047,789 $1,199,723
-------- --------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Purchased power........................................ 296,884 423,519 556,475 786,186
Other operating costs.................................. 80,843 80,899 167,660 151,321
Provision for depreciation and amortization............ 75,901 74,296 170,602 171,269
General taxes.......................................... 14,738 12,964 30,670 28,776
Income taxes (benefit)................................. 26,343 (27,172) 35,456 8,563
-------- --------- ---------- ----------
Total operating expenses and taxes................. 494,709 564,506 960,863 1,146,115
-------- --------- ---------- ----------
OPERATING INCOME (LOSS)................................... 54,956 (21,735) 86,926 53,608
OTHER INCOME.............................................. 1,104 2,264 2,607 3,440
NET INTEREST CHARGES:
Interest on long-term debt............................. 19,803 22,667 40,531 45,979
Allowance for borrowed funds used during construction.. (151) (111) (271) (234)
Deferred interest...................................... (891) (2,924) (1,814) (6,126)
Other interest expense (credit)........................ 463 104 853 (55)
Subsidiary's preferred stock dividend requirements..... -- 2,674 -- 5,348
-------- --------- ---------- ----------
Net interest charges................................. 19,224 22,410 39,299 44,912
-------- --------- ---------- ----------
NET INCOME (LOSS)......................................... 36,836 (41,881) 50,234 12,136
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 125 (488) 250 (363)
-------- --------- ---------- ----------
EARNINGS (LOSS) ON COMMON STOCK........................... $ 36,711 $ (41,393) $ 49,984 $ 12,499
======== ========= ========== ==========
COMPREHENSIVE INCOME:
NET INCOME................................................ $ 36,836 $ (41,881) $ 50,234 $ 12,136
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- (103,420) -- (103,420)
Unrealized gain (loss) on derivative hedges............ 59 (3,336) 44 (3,306)
Unrealized gain (loss) on available for sale
securities ........................................... -- -- (4) --
-------- --------- ---------- ----------
Other comprehensive income (loss).................... 59 (106,756) 40 (106,726)
Income tax related to other comprehensive income....... -- 42,733 -- 42,733
-------- --------- ---------- ----------
Other comprehensive income (loss), net of tax........ 59 (64,023) 40 (63,993)
-------- --------- ---------- ----------
TOTAL COMPREHENSIVE INCOME (LOSS)......................... $ 36,895 $(105,904) $ 50,274 $ (51,857)
======== ========= ========== ==========
The preceding Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company are an integral part of these statements.
118
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $3,689,267 $3,642,467
Less-Accumulated provision for depreciation.................................... 1,393,668 1,367,042
---------- ----------
2,295,599 2,275,425
Construction work in progress.................................................. 75,071 48,985
---------- ----------
2,370,670 2,324,410
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 128,576 125,945
Nuclear fuel disposal trust.................................................... 154,754 155,774
Long-term notes receivable from associated companies........................... 19,990 19,579
Other.......................................................................... 18,192 18,744
---------- ----------
321,512 320,042
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 282 271
Receivables-
Customers (less accumulated provisions of $3,572,842 and $4,296,000,
respectively, for uncollectible accounts).................................. 242,244 198,061
Associated companies......................................................... 27,836 70,012
Other (less accumulated provisions of $937,155 and $1,183,000,
respectively, for uncollectible accounts).................................. 36,561 46,411
Materials and supplies, at average cost........................................ 2,133 2,480
Prepayments and other.......................................................... 49,083 49,360
---------- ----------
358,139 366,595
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 2,324,357 2,558,214
Goodwill....................................................................... 1,995,907 2,001,302
Other.......................................................................... 4,050 8,481
---------- ----------
4,324,314 4,567,997
---------- ----------
$7,374,635 $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........................................................ 3,022,333 3,029,894
Accumulated other comprehensive loss......................................... (51,725) (51,765)
Retained earnings............................................................ 52,117 22,132
---------- ----------
Total common stockholder's equity........................................ 3,176,438 3,153,974
Preferred stock not subject to mandatory redemption............................ 12,649 12,649
Long-term debt................................................................. 1,251,898 1,095,991
---------- ----------
4,440,985 4,262,614
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 16,510 175,921
Notes payable to associated companies.......................................... 158,793 230,985
Accounts payable-
Associated companies......................................................... 17,188 42,410
Other........................................................................ 131,981 105,815
Accrued taxes................................................................. 64,688 919
Accrued interest............................................................... 9,615 14,843
Other.......................................................................... 9,784 58,094
---------- ----------
408,559 628,987
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 592,172 640,208
Accumulated deferred investment tax credits.................................... 6,918 7,711
Power purchase contract loss liability ........................................ 1,359,316 1,473,070
Nuclear fuel disposal costs.................................................... 168,719 167,936
Asset retirement obligation.................................................... 112,929 109,851
Retirement benefits............................................................ 150,451 159,219
Other.......................................................................... 134,586 129,448
---------- ----------
2,525,091 2,687,443
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
---------- ----------
$7,374,635 $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.
119
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ------------------------
2004 2003 2004 2003
-------- -------- ---------- ----------
Restated Restated
(See Note 2) (See Note 2)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 36,836 $(41,881) $ 50,234 $ 12,136
Adjustments to reconcile net income (loss) to net
cash from operating activities-
Provision for depreciation and amortization........ 75,901 74,296 170,602 171,269
Other amortization................................. 24 (102) 48 83
Deferred costs, net................................ (29,268) (70,564) (78,390) (142,452)
Deferred income taxes, net......................... (19,580) (31,981) (18,953) (17,004)
Investment tax credits, net........................ (397) (575) (794) (1,150)
Disallowed regulatory assets (see Note 6).......... -- 152,500 -- 152,500
Receivables........................................ 6,405 (87,390) 7,843 (67,602)
Materials and supplies............................. (11) (546) 347 (772)
Prepayments and other current assets............... (24,099) (86,491) 277 (70,447)
Accounts payable................................... 16,294 102,517 945 12,339
Accrued taxes...................................... 14,288 (39,037) 63,768 6,120
Accrued interest................................... (16,006) (14,200) (5,228) (8,429)
Accrued retirement benefit obligation.............. 2,946 6,167 (8,768) 6,167
Other.............................................. (10,553) 3,563 (7,109) 9,597
-------- -------- -------- ---------
Net cash provided from (used for) operating
activities ..................................... 52,780 (33,724) 174,822 62,355
-------- -------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 300,000 158,789 300,000 158,789
Short-term borrowings, net from associated companies. 7,552 196,126 -- 196,126
Redemptions and Repayments-
Preferred stock...................................... -- (125,244) -- (125,244)
Long-term debt....................................... (293,477) (163,725) (297,068) (173,815)
Short-term borrowings, net........................... -- -- (72,192) --
Dividend Payments-
Common stock......................................... (15,000) (39,000) (20,000) (128,000)
Preferred stock...................................... (125) 125 (250) --
-------- -------- -------- ---------
Net cash provided from (used for) financing
activities ..................................... (1,050) 27,071 (89,510) (72,144)
-------- -------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (55,213) (33,509) (83,425) (58,060)
Decommissioning trust investments...................... (724) (1,189) (1,447) (1,189)
Loan repayments from (loans to) associated
companies, net ....................................... 645 52,608 (411) 77,358
Other.................................................. 3,562 (7,066) (18) (7,116)
-------- -------- -------- ---------
Net cash provided from (used for) investing
activities ..................................... (51,730) 10,844 (85,301) 10,993
-------- -------- -------- ---------
Net increase in cash and cash equivalents................. -- 4,191 11 1,204
Cash and cash equivalents at beginning of period.......... 282 1,836 271 4,823
-------- -------- -------- ---------
Cash and cash equivalents at end of period................ $ 282 $ 6,027 $ 282 $ 6,027
======== ======== ======== =========
The preceding Notes to Consolidated Financial Statements as they relate to
Jersey Power & Light Company are an integral part of these statements.
120
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and six-month periods ended June 30, 2004 and 2003.
These interim financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 and six-month periods ended June 30, 2003.
We previously audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), 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 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
August 6, 2004
121
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 the Consolidated Financial Statements,
JCP&L's quarterly results for the second quarter and first six months 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 $3.0 million ($1.8 million
after-tax) in the second quarter of 2003 and $3.2 million ($1.9 million
after-tax) for the first six months 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. In addition, 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 JCP&L'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 results in 2003.
Results Of Operations
- --------------------
Earnings on common stock in the second quarter of 2004 increased to
$37 million from a loss of $41 million in the same period of 2003 as a result of
non-cash charges recorded in the second quarter of 2003 aggregating $159 million
($94 million after tax) due to a rate case decision disallowing recovery of
those costs (see Regulatory Matters). Excluding the impact of those non-cash
charges, earnings on common stock in the second quarter of 2003 were $53
million. Earnings on common stock during the first six months of 2004 were $50
million compared to $12 million for the same period of 2003. Earnings before the
non-cash charges related to the rate case decision were $107 million for the
first six months of 2003.
Operating revenues increased $7 million or 1.3% in the second quarter
of 2004, but decreased $152 million or 12.7% in the first six months of 2004,
compared with the same periods in 2003. Wholesale revenues increased $17 million
in the second quarter from the previous year, but declined $55 million in the
first six months of 2004. JCP&L entered into long-term power purchase agreements
in connection with the divestiture of its generation facilities and was selling
any power in excess of its retail customer needs to the wholesale market. The
long-term purchase agreements ended after the first quarter of 2003 and as a
result, sales to the wholesale market decreased. A higher level of customer
shopping reduced retail generation sales by 20.0% in the second quarter and
22.0% in the first six months of 2004 compared to the same periods of 2003.
Lower retail generation sales were more than offset by higher unit prices
reflecting the results of the BGS auction (see Regulatory Matters) and increased
retail generation sales revenues by $13 million in the second quarter; retail
generation sales revenues were relatively unchanged for the first half of 2004.
Distribution deliveries increased by 9.1% in the second quarter and
5.0% in the first six months of 2004 compared with the same periods of 2003. The
increase in deliveries in the second quarter of 2004 was based on strong demand
in the residential (15.4%) and commercial (8.0%) sectors due to warmer weather,
but was partially offset by a 1.0% decrease in deliveries to industrial
customers. Increases in all retail sectors for the first half of 2004 reflected
the second quarter increases in residential and commercial sectors, as well as
higher deliveries to industrial customers (2.3%) in part due to an improving
economy. The impact of the increased volume was more than offset by lower unit
prices which reduced revenues from electricity throughput by $30 million for the
quarter and $92 million for the first six months of 2004. In July 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
decrease in distribution revenues include the impact of the lower rates - $11
million in the second quarter and $44 million in the first six months of 2004.
Changes in distribution deliveries in the second quarter and first
half of 2004 compared with the same periods of 2003 are summarized in the
following table:
122
Changes in Kilowatt-Hour Deliveries Three Months Six Months
---------------------------------------------------------------------------
Increase (Decrease)
Residential........................... 15.4% 7.4%
Commercial............................ 8.0% 3.9%
Industrial............................ (1.0)% 2.3%
--------------------------------------------------------------------------
Total Distribution Deliveries........... 9.1% 5.0%
==========================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $70 million in the
second quarter and $185 million in the first six months of 2004 compared to the
same periods of 2003. The following table presents changes from the prior year
by expense category.
Operating Expenses and Taxes - Changes Three Months Six Months
------------------------------------------------------------------------------
Increase (Decrease) (In millions)
Purchased power costs........................... $(127) $(229)
Other operating costs........................... -- 16
------------------------------------------------------------------------------
Total operation and maintenance expenses...... (127) (213)
Provision for depreciation and amortization..... 2 (1)
General taxes................................... 2 2
Income taxes.................................... 53 27
------------------------------------------------------------------------------
Net decrease in operating expenses and taxes.. $ (70) $(185)
==============================================================================
The changes in purchased power costs and provision for deprecation and
amortization include the non-cash charges in the second quarter of 2003 for
amounts disallowed in the July 2003 JCP&L rate case decision (see Regulatory
Matters) - $153 million of deferred purchased power costs and $6 million charged
to depreciation and amortization. Excluding the disallowed deferred energy
costs, purchased power costs increased $26 million in the second quarter and
decreased $76 million in the first half of 2004, compared to the corresponding
periods of 2003. Kilowatt-hour purchases decreased due to lower generation sales
in both the quarter and the first six months of 2004. Increased unit costs due
to changes in the deferred energy and capacity costs more than offset the effect
of lower kilowatt-hour purchases in the second quarter of 2004 and only
partially offset the effect of reduced kilowatt-hour purchases for the first six
months of 2004. The increase in other operating costs for the first six months
of 2004 was primarily due to JCP&L's accelerated reliability program. Excluding
the amounts disallowed in the July 2003 JCP&L rate decision, depreciation and
amortization increased $8 million in the second quarter and $5 million for the
first six months of 2004, reflecting an increased level of regulatory asset
amortization from the rate decision partially offset by lower depreciation rates
and a $5 million reduction in the second quarter of 2004 related to an interest
calculation on the disallowances (see Regulatory Matters).
Net Interest Charges
Net interest charges decreased by $3 million in the second quarter and
$6 million in the first six months of 2004 compared with the same periods of
2003, reflecting debt redemptions since June 30, 2003. Those decreases were
partially offset by interest on $300 million of bonds issued in April 2004 which
were used to redeem currently outstanding securities and to reduce short-term
debt.
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
materially 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
There was no change as of June 30, 2004 and December 31, 2003 in
JCP&L's cash and cash equivalents of $0.3 million.
Cash Flows From Operating Activities
Cash provided from operating activities during the second quarter and
first six months of 2004, compared to the corresponding periods of 2003, were as
follows:
123
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
Operating Cash Flows 2004 2003 2004 2003
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $ 64 $ 82 $123 $ 175
Working capital and other (11) (116) 52 (113)
------------------------------------------------------------------------
Total ............ $ 53 $ (34) $175 $ 62
========================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash from operating activities increased $87 million in the second
quarter of 2004 compared to the same period in 2003 due to a $105 million
increase from changes in working capital, partially offset by an $18 million
decrease in cash earnings. The change in working capital primarily reflects
increased collections of receivables, lower prepayments and higher accrued
taxes. The decrease in cash earnings is due to higher purchased power costs in
the second quarter of 2004.
Net cash from operating activities increased $113 million in the first
half of 2004 compared to the same period in 2003 due to a $165 million increase
from changes in working capital partially offset by a $52 million decrease in
cash earnings. The change in working capital primarily reflects increased
collections of receivables, lower prepayments and higher accrued taxes. The
decrease in cash earnings is primarily due to lower operating revenues and
higher purchased power costs in the first six months of 2004.
Cash Flows From Financing Activities
In the second quarter of 2004, net cash used for financing activities
was $1 million compared to net cash provided from financing activities of $27
million in the second quarter of 2003. The change primarily reflects a $52
million increase in net debt and preferred stock redemptions partially offset by
a $24 million decrease in common stock dividend payments to FirstEnergy. Net
cash used in financing activities increased to $90 million in the first half of
2004 compared to $72 million in the same period of 2003. The increase resulted
from a $125 million increase in net debt and preferred stock redemptions and a
$108 million decrease in common stock dividend payments to FirstEnergy.
JCP&L will not issue FMB other than as collateral for senior notes,
since its senior note indentures prohibit (subject to certain exceptions) it
from issuing any debt which is senior to the senior notes. As of June 30, 2004,
JCP&L had the capability to issue $611 million of additional senior notes with
FMB as collateral. Based upon applicable earnings coverage tests, JCP&L could
issue a total of $470 million of preferred stock (assuming no additional debt
was issued) as of June 30, 2004.
On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes
due 2016. The proceeds of this transaction were 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 2025. 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 reduced
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
second quarter of 2004 was 1.39%.
On April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that, FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted, that in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility
through debt reduction and divestiture of non-core assets, FirstEnergy's
integrated regional strategy, and strong liquidity as credit strengths. Moody's
noted the substantial debt burden associated with the GPU merger, fully
competitive generating markets, and modest growth in markets served as credit
challenges for FirstEnergy. Moody's also noted that a "track record of improving
financial condition, especially a track record of debt reduction, could cause
the ratings to go up" and that the opposite development could cause the ratings
to go down.
124
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in
response to changes in the industry. As a result of its revised methodology for
evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility
companies including JCP&L. JCP&L's FMB credit rating was upgraded to BBB+ from
BBB.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $52 million and $85
million in the second quarter and first half of 2004, respectively, compared to
$11 million provided from investing activities in both periods of 2003. The
change in both periods was due to increased capital expenditures and decreased
loan repayments from associated companies.
During the second half of 2004, capital requirements for property
additions are expected to be about $57 million. JCP&L has additional
requirements of approximately $9 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.
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 second quarter and first six months of 2004 is
summarized in the following table:
Increase (Decrease) in the Fair Value Three Months Ended Six Months Ended
of Commodity Derivative Contracts June 30, 2004 June 30, 2004
- -----------------------------------------------------------------------------------------------------------------------
Non-Hedge Hedge Total Non-Hedge Hedge Total
--------- ----- ----- --------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Net asset at beginning of period....................... $ 15 $ -- $ 15 $ 16 $ -- $ 16
New contract value when entered........................ -- -- -- -- -- --
Changes in value of existing contracts................. -- -- -- (1) -- (1)
Change in techniques/assumptions....................... -- -- -- -- -- --
Settled contracts...................................... -- -- -- -- -- --
- --------------------------------------------------------------------------------------- -----------------------------
Net Assets - Derivative Contracts at end of period (1). $ 15 $ -- $ 15 $ 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 June 30, 2004:
Non-Hedge Hedge Total
- -----------------------------------------------------------------------------
(In millions)
Current-
Other Assets............................ $-- $-- $--
Other Liabilities....................... -- -- --
Non-Current-
Other Deferred Charges.................. 15 -- 15
Other Liabilities....................... -- -- --
- ------------------------------------------------------------------------------
Net assets.............................. $15 $-- $15
==============================================================================
125
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(1) 2005 2006 2007 Thereafter Total
- ----------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(2)... $2 $3 $2 $ -- $ -- $ 7
Prices based on models................ -- -- -- 2 6 8
- ----------------------------------------------------------------------------------------------------------
Total(3).......................... $2 $3 $2 $ 2 $ 6 $ 15
==========================================================================================================
(1) For the last two quarters of 2004.
(2) Broker quote sheets.
(3) 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
June 30, 2004.
Equity Price Risk
Included in JCP&L's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $74
million and $69 million as of June 30, 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 June 30, 2004.
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 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 subsequent next six to twelve months.
During that period, JCP&L would 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. In
its final decision and order issued on May 17, 2004, the NJBPU clarified the
method for calculating interest attributable to the cost disallowances,
resulting in a $5.4 million reduction from the amount estimated in 2003. On June
1, 2004, JCP&L filed with the NJBPU a supplemental and amended motion for
rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited
reconsideration and rehearing on the following issues: (1) deferred cost
disallowances, (2) the capital structure including the rate of return, (3)
merger savings, (4) amortization of costs to achieve merger savings; and (5)
126
decommissioning. All other issues included in JCP&L's amended motion were
denied. Oral arguments were held on August 4, 2004. Management cannot predict
when a decision following the oral arguments may be announced by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU
which requested an increase in base rates of $36 million, reflecting the
recovery of system reliability costs and a higher return on equity. The filing
also requests an increase to the MTC deferred balance recovery of approximately
$20 million annually. The filing also fulfills the NJBPU requirement that a
Phase II proceeding be conducted and that any expenditures and projects
undertaken by JCP&L to increase its system reliability be reviewed.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed
testimony on June 7, 2004 supporting a continuation of the current level and
duration of the funding of TMI-2 decommissioning costs by JCP&L's customers,
without a reduction, termination or capping of the funding.
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 above. JCP&L's regulatory assets were
$2.3 billion and $2.6 billion as of June 30, 2004 and December 31, 2003,
respectively.
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 $45.8 million as of June 30, 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.
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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives below). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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
127
the future that could require additional, material expenditures. FirstEnergy has
not accrued a liability as of June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On April 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
With respect to each of the foregoing initiatives, FirstEnergy
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 (SRM) be hired to oversee the investigation. On
December 8, 2003, the SRM 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 and
procedures of JCP&L. The audit was expanded to include the July 2003 outage and
was completed in January 2004. On June 9, 2004, the NJBPU approved a stipulation
that incorporated the final SRM report and portions of the final Booth report.
JCP&L is awaiting the final NJBPU final order.
Legal Matters
Various lawsuits, claims, including claims for asbestos exposure, 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 wave
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.
128
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 were appealed to the Appellate Division. The Appellate Court
issued a decision on July 8, 2004, affirming the decertification of the
originally certified class but remanding for certification of a class limited to
those customers directly impacted by the outages of transformers in Red Bank,
New Jersey. On July 28, 2004, both plaintiffs and JCP&L appealed the decision of
the Appellate Division to the New Jersey Supreme Court. JCP&L is unable to
predict the outcome of these matters and no liability has been accrued as of
June 30, 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. 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.
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 by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and post-retirement benefit obligations are
allocated to its subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. JCP&L'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.
129
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions 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
half 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.
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 is
indicated, 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 judgment 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, 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 FCON 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
130
the carrying value of the goodwill. JCP&L's most recent 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 half of 2004, JCP&L reduced goodwill by $5 million for
pre-merger interest received on an income tax refund and other tax benefits. As
of June 30, 2004, JCP&L had $2 billion of goodwill.
New Accounting Standards And Interpretation
- -------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the
EITF on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. JCP&L does not
expect the adoption of EITF 03-1 to have a material impact on its consolidated
financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on the accounting for
the effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy
provided under the Medicare Act 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 consolidated financial statements.
For the quarter ended June 30, 2004, JCP&L evaluated its power
purchase agreements and determined that it is possible that six NUG entities
might be considered VIEs. JCP&L has requested but has not received the
information necessary to determine whether these entities are VIEs or whether
JCP&L is the primary beneficiary. As such, JCP&L applied the scope exception
that exempts enterprises unable to obtain the necessary information to evaluate
entities under FIN 46R. See Note 2 - Consolidation for a discussion of variable
interest entities.
131
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
2004 2003 2004 2003
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $242,044 $217,712 $502,942 $468,915
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Purchased power........................................ 131,266 107,643 274,722 242,934
Other operating costs.................................. 47,021 38,387 80,069 72,122
Provision for depreciation and amortization............ 32,773 32,801 68,168 66,909
General taxes.......................................... 16,687 15,538 34,423 32,398
Income taxes........................................... 751 4,785 8,731 11,983
-------- -------- -------- --------
Total operating expenses and taxes................. 228,498 199,154 466,113 426,346
-------- -------- -------- --------
OPERATING INCOME.......................................... 13,546 18,558 36,829 42,569
OTHER INCOME.............................................. 6,116 5,307 11,642 10,475
NET INTEREST CHARGES:
Interest on long-term debt............................. 12,238 9,342 22,385 19,881
Allowance for borrowed funds used during construction.. (72) (85) (143) (158)
Deferred interest...................................... -- (555) -- (995)
Other interest expense................................. 831 402 1,520 865
Subsidiary's preferred stock dividend requirements..... -- 1,889 -- 3,779
-------- -------- -------- --------
Net interest charges................................. 12,997 10,993 23,762 23,372
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE................................................. 6,665 12,872 24,709 29,672
Cumulative effect of accounting change (net of income
taxes of $154,000) (Note 2)............................ -- -- -- 217
-------- -------- -------- --------
NET INCOME................................................ 6,665 12,872 24,709 29,889
-------- -------- -------- --------
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- (62,101) -- (62,101)
Unrealized gain (loss) on derivative hedges............ (6) 78 (3,266) 78
Unrealized gain (loss) on available for sale securities (38) 18 (25) 44
-------- -------- -------- --------
Other comprehensive loss ............................ (44) (62,005) (3,291) (61,979)
Income tax related to other comprehensive loss......... -- 25,660 -- 25,660
-------- -------- -------- --------
Other comprehensive loss, net of tax................. (44) (36,345) (3,291) (36,319)
-------- -------- -------- --------
TOTAL COMPREHENSIVE INCOME (LOSS)......................... $ 6,621 $(23,473) $ 21,418 $ (6,430)
======== ======== ======== ========
The preceding Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are an integral part of these statements.
132
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $1,855,270 $1,838,567
Less-Accumulated provision for depreciation.................................... 785,289 772,123
---------- ----------
1,069,981 1,066,444
Construction work in progress.................................................. 20,293 21,980
---------- ----------
1,090,274 1,088,424
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 199,038 192,409
Long-term notes receivable from associated companies........................... 10,587 9,892
Other.......................................................................... 33,972 34,922
---------- ----------
243,597 237,223
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 120 121
Notes receivable from associated companies..................................... 40,807 10,467
Receivables-
Customers (less accumulated provisions of $4,725,000 and $4,943,000,
respectively, for uncollectible accounts).................................. 115,787 118,933
Associated companies......................................................... 21,640 45,934
Other (less accumulated provisions of $28,000 and $68,000, respectively,
for uncollectible accounts)................................................ 17,648 22,750
Prepayments and other.......................................................... 35,889 6,600
---------- ----------
231,891 204,805
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 946,210 1,028,432
Goodwill....................................................................... 877,610 884,279
Other.......................................................................... 23,100 30,824
---------- ----------
1,846,920 1,943,535
---------- ----------
$3,412,682 $3,473,987
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding................................................. $1,294,257 $1,298,130
Accumulated other comprehensive loss......................................... (35,765) (32,474)
Retained earnings............................................................ 26,720 27,011
---------- ----------
Total common stockholder's equity.......................................... 1,285,212 1,292,667
Long-term debt and other long-term obligations................................. 707,958 636,301
---------- ----------
1,993,170 1,928,968
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 70,469 40,469
Notes payable to associated companies.......................................... -- 65,335
Accounts payable-
Associated companies......................................................... 41,948 45,459
Other........................................................................ 32,068 33,878
Accrued taxes................................................................. 2,652 8,762
Accrued interest............................................................... 14,727 11,848
Other.......................................................................... 36,265 22,162
---------- ----------
198,129 227,913
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 286,704 297,140
Power purchase contract loss liability......................................... 500,864 584,340
Asset retirement obligation.................................................... 216,390 210,178
Retirement benefits ........................................................... 106,316 105,552
Other.......................................................................... 111,109 119,896
---------- ----------
1,221,383 1,317,106
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
---------- ----------
$3,412,682 $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.
133
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- -----------------------
2004 2003 2004 2003
-------- --------- --------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 6,665 $ 12,872 $ 24,709 $ 29,889
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 32,773 32,801 68,168 66,909
Deferred costs, net................................ (13,195) (20,383) (29,987) (31,150)
Deferred income taxes, net......................... (7,746) 8,280 (5,107) 9,665
Amortization of investment tax credits............. (206) (205) (412) (410)
Accrued retirement benefit obligation.............. (309) 3,523 765 3,523
Accrued compensation, net.......................... 186 6,431 (448) 6,327
Cumulative effect of accounting change (Note 2).... -- -- -- (371)
Receivables........................................ 26,775 (28,290) 32,542 (9,946)
Materials and supplies............................. 18 -- 36 (139)
Prepayments and other current assets............... 7,293 11,504 (29,325) (18,636)
Accounts payable................................... (12,169) 52,329 (5,321) 84,297
Accrued taxes...................................... (4,564) (758) (6,110) (12,674)
Accrued interest................................... 7,344 1,008 2,879 (3,790)
Other.............................................. 6,040 (7,280) (2,225) (18,893)
-------- --------- --------- --------
Net cash provided from operating activities...... 48,905 71,832 50,164 104,601
-------- --------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- -- 247,607 247,696
Redemptions and Repayments-
Long-term debt....................................... (100,000) (190,435) (150,435) (230,435)
Short-term borrowings, net........................... -- (44,547) (65,335) (67,634)
Dividend Payments-
Common stock......................................... (20,000) (20,000) (25,000) (20,000)
-------- --------- --------- --------
Net cash provided from (used for) financing
activities ..................................... (120,000) (254,982) 6,837 (70,373)
-------- --------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (12,381) (9,569) (21,343) (19,902)
Contributions to nuclear decommissioning trusts........ (2,371) (2,432) (4,742) (4,803)
Loan repayments from (loans to) associated
companies, net ....................................... 85,767 (16,705) (31,035) (24,710)
Other.................................................. 80 (385) 118 (168)
-------- --------- --------- --------
Net cash provided from (used for) investing
activities ..................................... 71,095 (29,091) (57,002) (49,583)
-------- --------- --------- --------
Net decrease in cash and cash equivalents................. -- (212,241) (1) (15,355)
Cash and cash equivalents at beginning of period.......... 120 212,571 121 15,685
-------- --------- --------- --------
Cash and cash equivalents at end of period................ $ 120 $ 330 $ 120 $ 330
======== ========= ========= ========
The preceding Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are an integral part of these statements.
134
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and six-month periods ended June 30, 2004 and 2003.
These interim financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 the standards of the Public Company
Accounting Oversight Board (United States), 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 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
August 6, 2004
135
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 second quarter of 2004 decreased to $7 million from
$13 million in the second quarter of 2003. Increased purchased power costs,
transmission costs and net interest charges were partially offset by increased
operating revenues. During the first six months of 2004, net income decreased to
$25 million from $30 million in the first six months of 2003. Net income in the
first half of 2003 included an after-tax credit of $0.2 million from the
cumulative effect of an accounting change due to the adoption of SFAS 143. Net
income decreased in the first six months of 2004, as a result of higher
purchased power and transmission costs, partially offset by higher operating
revenues. The impact of these adjustments was not material to Met-Ed's
Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any
quarter of 2003. 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 Met-Ed'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 results in 2003.
Operating revenues increased by $24 million, or 11.2% in the second
quarter of 2004 compared with the second quarter of 2003. Higher revenues
resulted principally from increased distribution revenues of $12 million and
generation sales revenues of $10 million. Revenues from electricity throughput
increased as a result of higher unit prices and increased sales volume. The
increase in distribution deliveries was due to higher consumption by residential
and commercial customers (reflecting warmer weather in the second quarter of
2004) which was partially offset by lower deliveries to industrial customers.
The increase in generation sales revenues was due to higher kilowatt-hour sales
of 15.7% which were partially offset by lower unit prices. Generation sales
increased 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 9.0% in the second quarter of 2004 from 18.3% in the
same period of 2003.
Operating revenues increased by $34 million, or 7.3% in the first six
months of 2004 compared with the first six months of 2003. Higher revenues
resulted primarily from a $22 million increase from electricity throughput as a
result of warmer weather in the second quarter of 2004, partially offset by
lower unit prices. Retail generation kilowatt-hour sales increased by 11.5% in
the first six months of 2004 resulting in an increase in operating revenues of
$12 million. Sales of electric generation by alternative suppliers as a percent
of total sales delivered in Met-Ed's franchise area decreased to 9.7% in the
first six months in 2004 from 17.0% in the same period in 2003. The change in
unit prices for generation and distribution transition revenues reflected the
impact of the October 2003 PPUC order to change those rates to the previous PPUC
Restructuring Settlement order levels (see Regulatory Matters). This change
resulted in lower generation revenues unit prices and the corresponding increase
in distribution transition revenue unit prices.
Changes in distribution deliveries in the second quarter and first six
months of 2004 from the same periods of 2003 are summarized in the following
table:
Changes in Kilowatt-Hour Sales Three Months Six Months
---------------------------------------------------------------------
Increase (Decrease)
Distribution Deliveries:
Residential............................. 9.2% 3.4%
Commercial.............................. 5.9% 4.9%
Industrial.............................. (2.9)% (0.8)%
-------------------------------------------------------------------
Total Distribution Deliveries............. 3.8% 2.5%
===================================================================
136
Operating Expenses and Taxes
Total operating expenses and taxes increased $29 million in the second
quarter and $40 million in the first six months of 2004 compared to the same
periods of 2003. The following table presents changes from the prior year by
expense category.
Operating Expenses and Taxes - Changes Three Months Six Months
-------------------------------------------------------------------------------
Increase (Decrease) (In millions)
Purchased power costs............................ $24 $32
Other operating costs............................ 8 8
----------------------------------------------------------------------------
Total operation and maintenance expenses....... 32 40
Provision for depreciation and amortization...... -- 1
General taxes.................................... 1 2
Income taxes..................................... (4) (3)
-----------------------------------------------------------------------------
Net increase in operating expenses and taxes... $29 $40
=============================================================================
Purchased power costs were $24 million higher in the second quarter of
2004 from the same quarter of last year due to increased PLR kilowatt-hour
purchases from FES (due to increased generation sales requirements), partially
offset by reduced power from NUG sources. Other operating costs increased by $8
million in the second quarter of 2004 primarily due to higher vegetation
management costs and PJM transmission costs, which were assumed by Met-Ed in the
second quarter of 2004 due to a change in the PLR agreement with FES. General
taxes increased by $1 million primarily due to higher gross receipt taxes in the
second quarter of 2004 compared to the second quarter of 2003.
Purchased power costs were $32 million higher for the first six months
of 2004 compared to the same period of 2003 due to increased PLR kilowatt-hour
purchases from FES (due to increased generation sales requirements), partially
offset by reduced power from NUG sources. Other operating costs increased by $8
million due to higher vegetation management and transmission costs during the
second quarter of 2004. Depreciation and amortization expenses were $1 million
higher due to increased amortization of regulatory assets related to CTC revenue
recovery. General taxes increased by $2 million due to gross receipt taxes and
higher payroll taxes related to the transfer of employees to Met-Ed from GPUS.
Net Interest Charges
Net interest charges increased in the 2004 periods compared to the
respective 2003 periods primarily due to increased interest on long-term debt,
as a result of the issuance of $250 million of senior notes at the end of the
first quarter of 2004. This was partially offset by the redemption of $50
million of long-term debt in the first quarter of 2004 and $100 million of
unsecured subordinated debentures in the second quarter of 2004. The remaining
proceeds from the senior note issuance were used for the redemption of
short-term borrowings, and will be used to retire additional long-term debt in
the third quarter of 2004. Net interest charges also increased due to the
elimination of deferred interest for PLR energy costs in the third quarter of
2003.
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 two 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 June 30, 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 during the second quarter and
first six months of 2004, compared with the corresponding periods of 2003, were
as follows:
137
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
Operating Cash Flows 2004 2003 2004 2003
------------------------------------------------------------------------
(In millions)
Cash earnings (1)....... $19 $43 $58 $ 85
Working capital and other 30 29 (8) 20
------------------------------------------------------------------------
Total................... $49 $72 $50 $105
========================================================================
(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 $23 million in
the second quarter of 2004 from the second quarter of 2003 primarily as a result
of a $24 million decrease in cash earnings, partially offset by a $1 million
increase from changes in working capital. The change in cash earnings was due to
the increase in operating costs described above. The change in working capital
reflects a $55 million decrease in accounts receivable and a $6 million increase
in accrued interest offset by a $64 million decrease in accounts payable.
Net cash provided from operating activities decreased $55 million in
the first six months of 2004 from the same period of 2003 as a result of a $27
million decrease in cash earnings and a $28 million decrease from changes in
working capital and other changes. Cash earnings decreased primarily due to an
increase in other operating costs in the first half of 2004. The change in
working capital was due to a $90 million decrease in accounts payable and an $11
million increase in prepayments and other current assets, partially offset by a
$43 million decrease in accounts receivable and an increase in accrued taxes and
accrued interest aggregating $13 million.
Cash Flows From Financing Activities
In the second quarter of 2004, net cash used in financing activities
decreased to $120 million compared with $255 million in the second quarter of
2003 due to a $135 million decrease in debt reductions.
In the first six months of 2004, net cash provided from financing
activities was $7 million compared to $70 million of net cash used for financing
activities in the first six months of 2003. The change reflected an $82 million
decrease in net debt redemptions, partially offset by a $5 million increase in
common stock dividends to FirstEnergy.
As of June 30, 2004, Met-Ed had approximately $41 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 FMB
since its senior note indentures prohibit (subject to certain exceptions) it
from issuing any debt which is senior to the senior notes. Met-Ed is not limited
as to the amount of senior notes it may issue and has 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.
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
second quarter of 2004 was 1.39%.
In March 2004, Met-Ed completed a receivables financing arrangement
which provided borrowings of 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 June 30, 2004
and 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.
On April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted that, in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility via
debt reduction and divestiture of non-core assets, and FirstEnergy's integrated
138
regional strategy, and strong liquidity as credit strengths. Moody's noted the
substantial debt burden associated with the GPU merger, fully competitive
generating markets, and modest growth in markets served as credit challenges for
FirstEnergy. Moody's also noted that a "track record of improving financial
condition, especially a track record of debt reduction, could cause the ratings
to go up" and that the opposite development could cause the ratings to go down.
On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
Cash Flows From Investing Activities
In the second quarter of 2004, net cash provided from investing
activities totaled $71 million, compared to net cash used for investing
activities of $29 million in the second quarter of 2003. The change resulted
from a $102 million increase in loan repayments from associated companies offset
in part by higher property additions. Expenditures for property additions
primarily support Met-Ed's energy delivery operations.
In the first six months of 2004, net cash used in investing activities
totaled $57 million, compared to $50 million for the comparable period in 2003.
The change was due to a $6 million increase in loans to associated companies and
slightly higher property additions in the first half of 2004.
During the second half of 2004, capital requirements for property
additions are expected to be about $31 million. Met-Ed has additional
requirements of approximately $40 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.
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 second quarter of 2004 is summarized in the following table:
Increase (Decrease) in the Fair Value Three Months Ended Six Months Ended
of Commodity Derivative Contracts June 30, 2004 June 30, 2004
- -----------------------------------------------------------------------------------------------------------------------
Non-Hedge Hedge Total Non-Hedge Hedge Total
--------- ----- ----- --------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset at beginning of period........... $30 $ -- $30 $31 $ -- $31
New contract value when entered........................ -- -- -- -- -- --
Additions/Change in value of existing contracts........ -- -- -- (1) -- (1)
Change in techniques/assumptions....................... -- -- -- -- -- --
Settled contracts...................................... -- -- -- -- -- --
- --------------------------------------------------------------------------------------- -------------------------
Net Assets - Derivative Contracts as of June 30, 2004 (1) $30 $ -- $30 $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.
139
Derivatives included on the Consolidated Balance Sheet as of June 30, 2004:
Non-Hedge Hedge Total
(In millions)
Current-
Other Assets...................... $ -- $ -- $ --
Other Liabilities................. -- -- --
Non-Current-
Other Deferred Charges............ 30 -- 30
Other Liabilities.................
-------------------------------------------------------------------
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(1) 2005 2006 2007 Thereafter Total
- ---------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(2) $ 3 $ 5 $ 5 $-- $-- $13
Prices based on models -- -- -- 5 12 17
- ---------------------------------------------------------------------------------------------------------
Total(3) $ 3 $ 5 $ 5 $ 5 $12 $30
=========================================================================================================
(1) For the last two quarters of 2004.
(2) Broker quote sheets.
(3) 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
June 30, 2004.
Equity Price Risk
Included in Met-Ed's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $123
million and $114 million as of June 30, 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 June 30, 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
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 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.
140
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 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 2 and October 16 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.
Met-Ed purchases a portion of its PLR requirements from FES through a
wholesale power sale agreement. The PLR sale is 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 retains 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.
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 were $946 million and $1.03
billion as of June 30, 2004 and December 31, 2003, respectively.
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 $29,000 as of June 30, 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.
141
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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives below). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On April 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
With respect to each of the foregoing initiatives, FirstEnergy
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
142
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 required additional reporting
on reliability. The PPUC ordered all Pennsylvania utilities to begin filing
quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
approving the revised reliability benchmark and standards, including revised
benchmarks and standards for Met-Ed. The Order permitted Pennsylvania utilities
to file in a separate proceeding to revise the recomputed benchmarks and
standards if they have evidence, such as the impact of automated outage
management systems, on the accuracy of the PPUC computed reliability indices.
Met-Ed filed a Petition for Amendment of Benchmarks with the PPUC on May 26,
2004 seeking amendment of the benchmarks and standards due to their
implementation of automated outage management systems following restructuring.
No procedural schedule or hearing date has been set for this proceeding. Met-Ed
is unable to predict the outcome of this proceeding.
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
was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony
and Met-Ed's surrebuttal testimony was filed on July 23, 2004. Hearings were
held in early August 2004 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 the end of 2004. Met-Ed is unable to predict the outcome
of the investigation or the impact of the PPUC order.
Legal Matters
Various lawsuits, claims, including claims for asbestos exposure, 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. 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
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
143
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 by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and post-retirement benefit obligations are
allocated to its subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. Met-Ed'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 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. FirstEnergy reduced its 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
half 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.
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
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 judgment 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
144
discussed in FCON 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 most recent 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 half of 2004, Met-Ed reduced goodwill by $7 million for
pre-merger interest received on an income tax refund and other tax benefits. As
of June 30, 2004, Met-Ed had $877 million of goodwill.
New Accounting Standards And Interpretations
- --------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its
Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the EITF
on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. Met-Ed does not
expect the adoption of EITF 03-1 to have a material impact on its consolidated
financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on the accounting for
the effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy
provided under the Medicare Act 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 consolidated financial statements.
145
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
Restated Restated
(See Note 2) (See Note 2)
(In thousands)
OPERATING REVENUES........................................ $242,202 $231,926 $498,647 $486,802
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Purchased power........................................ 139,452 127,540 295,828 282,686
Other operating costs.................................. 45,980 40,838 85,888 83,915
Provision for depreciation and amortization............ 25,230 25,557 50,319 50,894
General taxes.......................................... 16,920 15,854 33,882 31,598
Income taxes........................................... 1,744 5,849 4,307 8,742
-------- -------- -------- --------
Total operating expenses and taxes................. 229,326 215,638 470,224 457,835
-------- -------- -------- --------
OPERATING INCOME.......................................... 12,876 16,288 28,423 28,967
OTHER INCOME.............................................. 447 534 363 342
NET INTEREST CHARGES:
Interest on long-term debt............................. 7,568 7,352 15,015 14,691
Allowance for borrowed funds used during construction.. (62) (99) (132) (180)
Deferred interest...................................... -- (1,149) 190 (2,145)
Other interest expense................................. 2,768 119 5,005 262
Subsidiary's preferred stock dividend requirements..... -- 1,889 -- 3,777
-------- -------- -------- --------
Net interest charges................................. 10,274 8,112 20,078 16,405
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE................................................. 3,049 8,710 8,708 12,904
-------- -------- -------- --------
Cumulative effect of accounting change (net of income
taxes of $777,000) (Note 2)........................... -- -- -- 1,096
-------- -------- -------- --------
NET INCOME................................................ 3,049 8,710 8,708 14,000
OTHER COMPREHENSIVE INCOME (LOSS):
Minimum liability for unfunded retirement benefits..... -- (91,820) -- (91,820)
Unrealized gain (loss) on derivative hedges............ (635) 72 (635) 72
Unrealized gain (loss) on available for sale securities (13) 8 (8) 16
-------- -------- -------- --------
Other comprehensive loss............................. (648) (91,740) (643) (91,732)
Income tax related to other comprehensive income....... -- 37,940 -- 37,940
-------- -------- -------- --------
Other comprehensive loss, net of tax................. (648) (53,800) (643) (53,792)
-------- -------- -------- --------
TOTAL COMPREHENSIVE INCOME (LOSS)......................... $ 2,401 $(45,090) $ 8,065 $(39,792)
======== ======== ======== ========
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.
146
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $1,987,527 $1,966,624
Less-Accumulated provision for depreciation.................................... 803,853 785,715
---------- ----------
1,183,674 1,180,909
Construction work in progress.................................................. 26,855 29,063
---------- ----------
1,210,529 1,209,972
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 103,442 102,673
Non-utility generation trusts.................................................. 93,907 43,864
Long-term notes receivable from associated companies........................... 13,814 13,794
Other.......................................................................... 19,138 19,635
---------- ----------
230,301 179,966
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 36 36
Receivables-
Customers (less accumulated provisions of $5,606,000 and $5,833,000,
respectively, for uncollectible accounts).................................. 119,313 124,462
Associated companies......................................................... 39,902 88,598
Other (less accumulated provisions of $310,000 and $399,000, respectively,
for uncollectible accounts)................................................ 16,117 15,767
Prepayments and other.......................................................... 37,460 2,511
---------- ----------
212,828 231,374
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 410,682 497,219
Goodwill....................................................................... 883,697 898,547
Accumulated deferred income tax benefits....................................... 13,014 16,642
Other.......................................................................... 17,375 18,523
---------- ----------
1,324,768 1,430,931
---------- ----------
$2,978,426 $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........................................................ 1,211,069 1,215,667
Accumulated other comprehensive loss......................................... (42,828) (42,185)
Retained earnings............................................................ 21,746 18,038
---------- ----------
Total common stockholder's equity.......................................... 1,295,799 1,297,332
Long-term debt and other long-term obligations................................. 492,796 438,764
---------- ----------
1,788,595 1,736,096
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt .............................................. 96,071 125,762
Notes payable to associated companies.......................................... 86,146 78,510
Accounts payable-
Associated companies......................................................... 42,850 55,831
Other........................................................................ 38,413 40,192
Accrued taxes................................................................. 1,131 8,705
Accrued interest............................................................... 9,945 12,694
Other.......................................................................... 37,250 21,764
---------- ----------
311,806 343,458
---------- ----------
NONCURRENT LIABILITIES:
Asset retirement obligation.................................................... 108,195 105,089
Power purchase contract loss liability......................................... 570,078 670,482
Retirement benefits............................................................ 148,721 145,081
Other.......................................................................... 51,031 52,037
---------- ----------
878,025 972,689
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)...............................
---------- ----------
$2,978,426 $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.
147
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
Restated Restated
(See Note 2) (See Note 2)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 3,049 $ 8,710 $ 8,708 $ 14,000
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 25,230 25,557 50,319 50,894
Deferred costs recoverable as regulatory assets.... (18,511) (23,741) (36,504) (35,397)
Deferred income taxes, net......................... (23,262) 4,131 2,225 (37,509)
Investment tax credits, net........................ (246) (247) (491) (494)
Accrued retirement benefit obligations............. 839 11,964 3,641 11,964
Accrued compensation, net.......................... (878) 8,790 1,377 8,852
Cumulative effect of accounting change (Note 2).... -- -- -- (1,873)
Receivables........................................ 65,624 3,352 53,495 8,792
Prepayments and other current assets............... 12,104 28,965 (34,950) (5,813)
Accounts payable................................... (4,022) 13,306 (14,760) 21,972
Accrued taxes...................................... (1,091) (27,404) (7,574) (120)
Accrued interest................................... (5,385) (5,565) (2,749) 114
Other.............................................. 20,635 15,980 24,289 8,828
--------- --------- --------- --------
Net cash provided from operating activities...... 74,086 63,798 47,026 44,210
--------- --------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- -- 150,000 --
Short-term borrowings, net........................... 68,962 27,569 7,636 --
Redemptions and Repayments-
Long-term debt....................................... (125,108) (289) (125,212) (289)
Short-term borrowings, net........................... -- -- -- (62,858)
Dividend Payments-
Common stock......................................... (5,000) (16,000) (5,000) (16,000)
--------- --------- --------- --------
Net cash provided from (used for)
financing activities........................... (61,146) 11,280 27,424 (79,147)
--------- --------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (12,042) (13,159) (23,236) (19,471)
Nonutility generation trust withdrawals (contributions) -- -- (50,614) 106,327
Loan repayments from (loans to) associated
companies, net ....................................... 51 (61,987) (20) (61,987)
Other, net............................................. (949) 124 (580) 124
--------- --------- --------- --------
Net cash provided from (used for)
investing activities........................... (12,940) (75,022) (74,450) 24,993
--------- --------- --------- --------
Net increase (decrease) in cash and cash equivalents...... -- 56 -- (9,944)
Cash and cash equivalents at beginning of period.......... 36 310 36 10,310
--------- --------- --------- --------
Cash and cash equivalents at end of period................ $ 36 $ 366 $ 36 $ 366
========= ========= ========= ========
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.
148
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 June 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and six-month periods ended June 30, 2004 and 2003.
These interim financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 the
standards of the Public Company Accounting Oversight Board, 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 and six-month periods ended June 30, 2003.
We previously audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), 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 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
August 6, 2004
149
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.
Restatements Of Previously Reported Quarterly Results
- -----------------------------------------------------
As discussed in Note 2 to the Consolidated Financial Statements,
Penelec's quarterly results for the second quarter of 2003 have been restated to
correct the amounts reported for operating expenses. Penelec's costs which were
originally recorded as operating expenses and should have been capitalized to
construction were $0.7 million ($0.4 million after-tax) in the second quarter of
2003. The impact of these adjustments was not material to Penelec's Consolidated
Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003.
In addition, 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 Penelec'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 results in 2003.
Results of Operations
- --------------------
Net income in the second quarter of 2004 decreased to $3.0 million
from $8.7 million in the second quarter of 2003. Higher operating revenues were
more than offset by increased purchased power, other operating costs and net
interest charges as compared to the second quarter of 2003. During the first six
months of 2004, net income decreased to $8.7 million compared to $14.0 million
in the first six months of 2003. Net income in the first half 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
$8.7 million in the first six months of 2004, compared to $12.9 million for the
same period in 2003. The decrease in net income was the result of higher
purchased power costs, other operating costs and interest charges -partially
offset by higher operating revenues.
Operating revenues increased by $10.3 million, or 4.4% in the second
quarter of 2004 compared with the same period in 2003, primarily as a result of
higher distribution and generation revenues. Revenues from electricity
throughput increased by $11.2 million as a result of higher unit prices ($4.7
million) and a 7.1% increase in distribution deliveries. Penelec's distribution
deliveries increased in all sectors - including a 13.3% increase in industrial
deliveries in part due to an improving economy. Retail generation kilowatt-hour
sales increased by 8.3% as a result of higher kilowatt-hour sales to industrial
and commercial sectors, due to more customers returning from alternative
suppliers. Operating revenues increased $11.8 million, or 2.4% in the first six
months of 2004 compared to the same period in 2003, reflecting a 3.2% increase
in distribution deliveries and a corresponding increase in revenues of $20.4
million. Higher distribution deliveries to industrial, commercial and
residential customer sectors and higher transition revenues contributed to this
increase. Higher revenues from distribution deliveries were partially offset by
lower generation revenues of $4.5 million resulting from lower unit prices. The
change in unit prices for generation and distribution transition revenues
reflected the impact of the October 2003 PPUC order to change those rates to the
previous PPUC Restructuring Settlement order levels (see Regulatory Matters).
This change resulted in lower generation revenues unit prices and the
corresponding increase in distribution transition revenue unit prices.
Changes in electric generation sales and distribution deliveries in
the second quarter and the first six months of 2004 from the corresponding
periods of 2003 are summarized in the following table:
150
Changes in Kilowatt-Hour Sales Three Months Six Months
-------------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ 8.3% 4.8%
Wholesale............................. (100.0)% (100.0)%
---------------------------------------------------------------------
Total Electric Generation Sales......... 7.7% 4.7%
====================================================================
Distribution Deliveries:
Residential........................... 1.7% 2.6%
Commercial............................ 5.6% 2.5%
Industrial............................ 13.3% 4.6%
--------------------------------------------------------------------
Total Distribution Deliveries........... 7.1% 3.2%
====================================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased $13.7 million or 6.3% in
the second quarter of 2004 and $12.4 million, or 2.7% in the first six months of
2004 from the same periods of 2003. The following table presents changes from
the prior year by expense category.
Operating Expenses and Taxes - Changes Three Months Six Months
- --------------------------------------------------------------------------------
Increase (Decrease) (In millions)
Purchased power costs.......................... $11.9 $13.1
Other operating costs.......................... 5.1 2.0
---------------------------------------------------------------------------
Total operation and maintenance expenses..... 17.0 15.1
Provision for depreciation and amortization.... (0.3) (0.6)
General taxes.................................. 1.1 2.3
Income taxes................................... (4.1) (4.4)
---------------------------------------------------------------------------
Total operating expenses and taxes........... $13.7 $12.4
===========================================================================
Higher purchased power costs in the second quarter of 2004 reflect
additional kilowatt-hours purchased to support increased generation sales
requirements, as well as higher unit costs. The higher purchased power costs in
the first half of 2004 were principally due to additional kilowatt-hours
purchased to support increased generation sales requirements. The increase in
other operating costs in the second quarter and first half of 2004 compared to
the same periods of 2003 primarily resulted from an increase of $8.5 million for
PJM transmission costs (which were assumed by Penelec in the second quarter of
2004 due to a change in the PLR agreement with FES) and higher energy delivery
costs related to increased vegetation management activities, partially offset by
decreased employee benefit costs.
Net Interest Charges
Net interest charges increased by $2.2 million in the second quarter
of 2004 and $3.7 million in the first half of 2004 compared with the same
periods of 2003, primarily due to Penelec changing from a net lender to the
money pool with associated companies in 2003 to a net borrower in 2004. The
change in funding position resulted from a $51 million refunding payment to a
NUG trust fund in 2004 compared to a $106 million withdrawal from the NUG trust
in 2003.
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
effect adjustment for unrecognized depreciation and 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 materially 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
There was no change as of June 30, 2004 and December 31, 2003 in
Penelec's cash and cash equivalents of $36,000.
151
Cash Flows From Operating Activities
Cash used for operating activities during the second quarter and
first six months of 2004 compared with the corresponding periods of 2003 were as
follows:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------------------------------------
Operating Cash Flows 2004 2003 2004 2003
---------------------------------------------------------------------
(In millions)
Cash earnings (loss) (1)... $(14) $35 $29 $10
Working capital and other.. 88 29 18 34
--------------------------------------------------------------------
Total...................... $ 74 $64 $47 $44
====================================================================
(1) Includes net income, depreciation and amortization,
deferred costs recoverable as regulatory assets, deferred
income taxes, investment tax credits and pension changes.
Net cash provided from operating activities increased to $74 million
in the second quarter and $47 million in the first half of 2004 compared with
the corresponding periods of 2003 of $64 million and $44 million, respectively.
The $10 million increase in the second quarter of 2004 was due to the $59
million increase in working capital partially offset by $49 million lower cash
earnings resulting from lower net income and changes in deferred income taxes.
For the first half of 2004 the increase was due to higher cash earnings of $19
million due to an increase in deferred income taxes offset by reductions in net
incXome, accrued retirement benefits and accrued compensation. The decrease in
working capital of $16 million for the six-month period was primarily due to a
decrease in accounts payable combined with an increase in accounts receivable,
partially offset by a decrease in prepayments.
Cash Flows From Financing Activities
Net cash used for financing activities increased by $72 million in the
second quarter of 2004 from the second quarter of 2003. The increase in cash
used primarily resulted from the redemption of $125 million of senior notes in
April 2004 - offset in part by the issuance of $69 million in short-term
borrowings. Net cash provided from financing activities of $27 million for the
first six months of 2004 compared to net cash used for financing activities of
$79 million for the first six months of 2003, represents the issuance in March
2004 of $150 million of long-term debt used to redeem $125 million of senior
notes in April 2004; Penelec's short-term borrowings were reduced by $63 million
in the first six months of 2003.
As of June 30, 2004, Penelec had about $86.1 million of short-term
indebtedness. Penelec will not issue FMB other than as collateral for senior
notes, since its senior note indentures prohibit (subject to certain exceptions)
it from issuing any debt which is senior to the senior notes. As of June 30,
2004, Penelec had the capability to issue $11.4 million of additional senior
notes based upon FMB collateral. Penelec had no restrictions on the issuance of
preferred stock.
Penelec 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
second quarter of 2004 was 1.39%.
In March 2004, Penelec completed a receivables financing arrangement
which provides for borrowings of 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 June
30, 2004 and 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 April 28, 2004, Moody's published a Liquidity Risk Assessment of
FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's
noted that FirstEnergy's committed credit facilities at the holding company
level provided a substantial source of liquidity. Moody's also noted that, in
the past year, FirstEnergy had lengthened the average maturity of its bank
facilities and had made reductions to its total consolidated debt level.
On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy
Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core
utility operations, management's focus on increasing financial flexibility via
debt reduction and divestiture of non-core assets, and FirstEnergy's integrated
regional strategy, and strong liquidity as credit strengths. Moody's noted the
substantial debt burden associated with the GPU merger, fully competitive
generating markets, and modest growth in markets served as credit challenges for
152
FirstEnergy. Moody's also noted that a "track record of improving financial
condition, especially a track record of debt reduction, could cause the ratings
to go up" and that the opposite development could cause the ratings to go down.
On June 14, S&P stated that the June 9, 2004 PUCO decision on
FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook
on FirstEnergy.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $13 million in the
second quarter of 2004 compared to $75 million in the second quarter of 2003.
The lower investing activities reflected reduced loans to associated companies.
Net cash used for investing activities was $74 million in the first six months
of 2004, compared with net cash of $25 million provided from investing
activities in the same period of 2003. The change in net cash resulted from a
$51 million refunding payment to a NUG trust fund in 2004 and a $106 million
withdrawal from the NUG trust in 2003. Expenditures for property additions
primarily support Penelec's energy delivery operations.
During the second half of 2004, capital requirements for property
additions are expected to be about $36 million. Penelec has additional
requirements of approximately $0.2 million for maturing long-term debt during
the remainder of 2004. In addition, Penelec announced it would optionally redeem
at par $100 million principal amount of its subordinated debentures in
connection with the concurrent off-balance sheet redemption at par of $100
million principal amount of Penelec Capital Trusts 7.34% Trust Preferred
Securities on September 1, 2004.These cash requirements are expected to be
satisfied from internal cash and short-term credit arrangements.
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.
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 second quarter and first six months of 2004 is summarized in the
following table:
Increase (Decrease) in the Fair Value Three Months Ended Six Months Ended
of Commodity Derivative Contracts June 30, 2004 June 30, 2004
- ----------------------------------------------------------------------------------------------------------------------
Non-Hedge Hedge Total Non-Hedge Hedge Total
--------- ----- ----- --------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Net asset at beginning of period....................... $15 $ -- $15 $15 $ -- $15
New contract value when entered........................ -- -- -- -- -- --
Additions/Increase in value of existing contracts...... -- -- -- -- -- --
Change in techniques/assumptions....................... -- -- -- -- -- --
Settled contracts...................................... -- -- -- -- -- --
- --------------------------------------------------------------------------------------- -------------------------
Net Assets - Derivative Contracts as of June 30, 2004 (1) $15 $ -- $15 $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) Includes $14 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.
153
Derivatives included on the Consolidated Balance Sheet as of June 30, 2004:
Non-Hedge Hedge Total
---------------------------------------------------------------------------
(In millions)
Current-
Other Assets....................... $ -- $ -- $ --
Other Liabilities.................. -- -- --
Non-Current-
Other Deferred Charges............. 15 -- 15
Other Liabilities.................. -- -- --
---------------------------------------------------------------------------
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(1) 2005 2006 2007 Thereafter Total
- ---------------------------------------------------------------------------------------------------------
(In millions)
Prices based on external sources(2) $ 2 $ 3 $ 2 $ -- $ -- $ 7
Prices based on models -- -- -- 2 6 8
- ---------------------------------------------------------------------------------------------------------
Total3 $ 2 $ 3 $ 2 $ 2 $ 6 $15
=========================================================================================================
(1) For the last two quarters of 2004.
(2) Broker quote sheets.
(3) 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
June 30, 2004.
Equity Price Risk
Included in Penelec's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $56
million and $54 million as of June 30, 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 June 30, 2004.
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 Matters
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 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 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. 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.
154
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 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, 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 2 and October 16 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.
Penelec purchases a portion of its PLR requirements from FES through a
wholesale power sale agreement. The PLR sale is 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 retains 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.
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 were $411
million and $497 million as of June 30, 2004 and December 31, 2003,
respectively.
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 $26,000 as of June 30, 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.
155
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.
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
implemented several initiatives, both prior to and since the August 14th power
outage, which are consistent with these and other recommendations and
collectively enhance the reliability of its electric system. FirstEnergy
certified to NERC on June 30, 2004, completion of various reliability
recommendations and further received independent verification of completion
status from a NERC verification team on July 14, 2004 (see Reliability
Initiatives below). FirstEnergy's implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. 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 June 30, 2004 for any expenditures in excess of
those actually incurred through that date.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas
and reliability coordinators requesting that a review of various reliability
practices be undertaken within 60 days. The Company issued its response on
December 15, 2003, confirming that its review had taken place and noted that it
was undertaking various enhancements to current practices. On February 10, 2004,
NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of
Future Cascading Blackouts. Approximately 20 of the recommendations were
directed at the FirstEnergy companies and broadly focused on initiatives that
were recommended for completion by June 30, 2004. These initiatives principally
related 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
implementation plan to NERC, which the NERC Board of Trustees subsequently
endorsed on May 7, 2004. The various initiatives required by NERC to be
completed by June 30, 2004 have been certified as complete to NERC (on June 30,
2004), with one minor exception related to reactive testing of certain
generators expected to be completed later this year. An independent NERC
verification team conducted an on-site review of the completion status,
reporting on July 14, 2004, that FirstEnergy had implemented the policies,
procedures and actions that were recommended to be completed by June 30, 2004,
with the exception noted by FirstEnergy. Implementation of the recommendations
has not required incremental material investment or upgrades to existing
equipment.
On April 5, 2004, the U.S. - Canada Power System Outage Task Force
issued a Final Report on the August 14, 2003 power outage. 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 recommended be
undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy completed the Task
Force recommendations that were directed toward FirstEnergy and reported
completion of those recommendations on June 30, 2004. Implementation of the
recommendations has not required incremental material investment or upgrades to
existing equipment.
With respect to each of the foregoing initiatives, FirstEnergy
requested and NERC provided, a technical assistance team of experts to provide
ongoing guidance and assistance in implementing and confirming timely and
successful completion. NERC thereafter assembled an independent verification
team to confirm implementation of NERC Recommended Actions to Prevent and
Mitigate the Impacts of Future Cascading Blackouts required to be completed by
June 30, 2004, as well as NERC recommendations contained in the Control Area
Readiness Audit Report required to be completed by summer 2004, and
recommendations in the Joint U.S. - Canada Power System Outage Task Force Report
directed toward FirstEnergy and required to be completed by June 30, 2004. The
NERC team reported, on July 14, 2004, that FirstEnergy has completed the
156
recommended policies, procedures, and actions required to be completed by June
30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
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 required additional reporting
on reliability. The PPUC ordered all Pennsylvania utilities to begin filing
quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
approving the revised reliability benchmark and standards, including revised
benchmarks and standards for Penelec. The Order permitted Pennsylvania utilities
to file in a separate proceeding to revise the recomputed benchmarks and
standards if they have evidence, such as the impact of automated outage
management systems, on the accuracy of the PPUC computed reliability indices.
Penelec filed a Petition for Amendment of Benchmarks with the PPUC on May 26,
2004 seeking amendment of the benchmarks and standards due to their
implementation of automated outage management systems following restructuring.
No procedural schedule or hearing date has been set for this proceeding. Penelec
is unable to predict the outcome of this proceeding.
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
was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony
and Penelec's surrebuttal testimony was filed on July 23, 2004. Hearings were
held in early August 2004 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 the end of 2004. Penelec is unable to predict the outcome
of the investigation or the impact of the PPUC order.
Legal Matters
Various lawsuits, claims, including claims for asbestos exposure, 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 its 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 the 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. Penelec
regularly reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. Penelec continually monitors its derivative contracts to determine if
its activities, expectations, intentions, assumptions and estimates remain
valid. As part of its normal operations, Penelec enters into commodity contracts
which increase the impact of derivative accounting judgments.
Revenue Recognition
Penelec follows the accrual method of accounting for revenues,
recognizing revenue for electricity that has been delivered to customers but not
yet billed through the end of the accounting period. The determination of
157
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 by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy's pension and post-retirement benefit obligations are
allocated to its subsidiaries employing the plan participants. Employee benefits
related to construction projects are capitalized. Penelec'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 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. FirstEnergy reduced its 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
half 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
is not required to fund its pension plans in 2004.
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, 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 would recognize a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
The calculation of future cash flows is based on assumptions,
estimates and judgment 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
158
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 FCON 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 an impairment is 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 most recent 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 six months of 2004, Penelec reduced goodwill by $15
million for pre-merger interest received on an income tax refund and other tax
benefits. As of June 30, 2004, Penelec had $884 million of goodwill.
New Accounting Standards And Interpretations
- --------------------------------------------
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and
Its Application to Certain Investments"
On March 31, 2004, the FASB ratified the consensus reached by the EITF
on the application guidance for Issue 03-1. EITF 03-1 provides a model for
determining when investments in certain debt and equity securities are
considered other than temporarily impaired. When an impairment is
other-than-temporary, the investment must be measured at fair value and the
impairment loss recognized in earnings. The recognition and measurement
provisions of EITF 03-1 are to be applied to other-than-temporary impairment
evaluations in reporting periods beginning after June 15, 2004. Penelec does not
expect the adoption of EITF 03-1 to have a material impact on its consolidated
financial statements.
FSP 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Issued in May 2004, FSP 106-2 provides guidance on accounting for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. The effect of the federal subsidy provided under the Medicare Act
on FirstEnergy's consolidated financial statements is described in Note 4.
FIN 46 (revised December 2003), "Consolidation of Variable
Interest Entities"
In December 2003, the FASB issued a revised interpretation of ARB 51
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 three and six
months ended June 30, 2004. See Note 2 for a discussion of Variable Interest
Entities.
159
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 June 30, 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.
160
PART II. OTHER INFORMATION
- ----------------------------
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the
discussions in Notes 3 and 6 of the Consolidated Financial Statements in Part I,
Item 1 of this Form 10-Q.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The annual meeting of FirstEnergy shareholders was held on May 18, 2004.
(b) At this meeting, the following persons were elected to FirstEnergy's Board
of Directors:
Number of Votes
--------------------------
For Withheld
----------- ----------
Paul T. Addison................... 263,606,710 19,612,877
Ernest J. Novak, Jr............... 271,779,183 11,440,404
John M. Pietruski................. 269,383,439 13,836,147
Catherine A. Rein................. 264,438,767 18,780,820
Robert C. Savage.................. 250,908,903 32,310,684
(c) At this meeting, the appointment of PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as auditor for the year 2004
was ratified:
Number of Votes
-----------------------------------------
For Against Abstentions
----------- --------- -----------
273,904,301 6,586,150 2,729,034
(d) At this meeting, amendments to the Amended Code of Regulations to
declassify the Board of Directors were approved (approval required 80% of
the common shares entitled to vote):
Number of Votes
-----------------------------------------
For Against Abstentions
----------- --------- -----------
272,395,791 7,230,086 3,593,698
(e) At this meeting, amendments to the Amended Articles of Incorporation and
Amended Code of Regulations to change certain voting requirements were not
approved (approval required 80% of the common shares entitled to vote):
Number of Votes
------------------------------------------------------------
Broker
For Against Abstentions Non-Votes
----------- --------- ----------- ------------
236,276,530 8,711,169 3,789,993 34,441,895
(f) At this meeting, the Executive Deferred Compensation Plan was approved
(approval required a majority of the votes cast):
Number of Votes
---------------------------------------------------------------
Broker
For Against Abstentions Non-Votes
----------- ---------- ----------- -----------
198,037,334 46,486,158 4,254,193 34,441,902
(g) At this meeting, the Deferred Compensation Plan for Outside Directors was
approved (approval required a majority of the votes cast):
Number of Votes
--------------------------------------------------------------
Broker
For Against Abstentions Non-Votes
----------- ---------- ----------- -----------
197,684,198 46,761,355 4,332,132 34,441,901
161
(h) At this meeting, a shareholder proposal that all future stock option grants
to employees be expensed in FirstEnergy's annual income statement was
approved (approval required a majority of the votes cast):
Number of Votes
-------------------------------------------------------------
Broker
For Against Abstentions Non-Votes
----------- ----------- ----------- -----------
132,425,617 107,442,673 8,940,886 34,410,411
(i) At this meeting, a shareholder proposal requesting that any shareholder
rights plan be submitted to shareholder vote was approved (approval
required a majority of the votes cast):
Number of Votes
-------------------------------------------------------------
Broker
For Against Abstentions Non-Votes
----------- ---------- ----------- -----------
171,180,303 73,342,244 4,344,407 34,352,632
(j) At this meeting, a shareholder proposal requesting that FirstEnergy publish
semi-annual and annual reports regarding its political contributions was
not approved (approval required a majority of votes cast):
Number of Votes
------------------------------------------------------------
Broker
For Against Abstentions Non-Votes
---------- ----------- ----------- -----------
22,381,838 208,449,067 17,905,069 34,483,612
(k) At this meeting, a shareholder proposal requesting that certain future
severance agreements with senior executives be submitted to shareholder
vote was approved (approval required a majority of votes cast):
Number of Votes
-----------------------------------------------------------
Broker
For Against Abstentions Non-Votes
----------- ---------- ----------- ---------
155,305,564 88,627,910 4,941,606 34,344,507
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 registered public accounting firm
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.
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.
162
FirstEnergy
-----------
15 Letter from independent registered public accounting firm
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 registered public accounting firm
31.1 Certification of chief executive officer, as adopted pursuan
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.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K,
neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec
have filed as an exhibit to this Form 10-Q any instrument with
respect to long-term debt if the respective total amount of
securities authorized thereunder does not exceed 10% of their
respective total assets of FirstEnergy and its subsidiaries on a
consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed
or Penelec but hereby agree to furnish to the Commission on request
any such documents.
(b) Reports on Form 8-K
FirstEnergy
-----------
FirstEnergy filed the following four reports on Form 8-K since March
31, 2004: A report dated May 24, 2004 reported that the Perry Nuclear Power
Plant was expected to return to service the following week. A report dated June
14, 2004 reported that the PUCO issued an order that included major
modifications to FirstEnergy's revised Rate Stabilization Plan application. A
report dated June 28, 2004 reported that the SEC has requested that FirstEnergy
provide information and documents related to the extended outage at the
Davis-Besse Nuclear Power Station. A report dated July 27, 2004 reported that
FirstEnergy had reached an agreement that resolves all pending securities and
derivative lawsuits filed against the Company and certain of its officers and
directors.
CEI and TE
----------
CEI and TE each filed the following three reports on Form 8-K since
March 31, 2004: A report dated May 24, 2004 reported that the Perry Nuclear
Power Plant was expected to return to service the following week. A report dated
June 14, 2004 reported that the PUCO issued an order that included major
modifications to FirstEnergy's revised Rate Stabilization Plan application. A
report dated June 28, 2004 reported that the SEC has requested that FirstEnergy
provide information and documents related to the extended outage at the
Davis-Besse Nuclear Power Station.
OE
--
OE filed the following two reports on Form 8-K since March 31, 2004:
A report dated May 24, 2004 reported that the Perry Nuclear Power Plant was
expected to return to service the following week. A report dated June 14, 2004
reported that the PUCO issued an order that included major modifications to
FirstEnergy's revised Rate Stabilization Plan application.
Penn
----
Penn filed one report on Form 8-K since March 31, 2004: A report
dated May 24, 2004 reported that the Perry Nuclear Power Plant was expected to
return to service the following week.
JCP&L, Met-Ed and Penelec
-------------------------
None.
163
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.
August 6, 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
164