Form 10Q/A 1st Quarter 2006
UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,
D. C. 20549
FORM
10-Q/A
Amendment
No. 1
(Mark
One)
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the
quarterly period ended March 31, 2006
OR
[
]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the transition period from
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to
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Commission
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Registrant;
State of Incorporation;
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I.R.S.
Employer
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File
Number
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Address;
and Telephone Number
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Identification
No.
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333-21011
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FIRSTENERGY
CORP.
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34-1843785
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(An
Ohio Corporation)
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-2578
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OHIO
EDISON COMPANY
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34-0437786
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3491
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PENNSYLVANIA
POWER COMPANY
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25-0718810
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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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 the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of "accelerated filer and large
accelerated filer" in Rule 12b-2 of the Exchange Act.
Large
Accelerated Filer (X)
|
FirstEnergy
Corp.
|
Accelerated
Filer (
)
|
N/A
|
Non-accelerated
Filer (X)
|
Ohio
Edison
Company and Pennsylvania Power
Company
|
Indicate
by check
mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the
Act).
Yes
(
)
No (X)
Indicate
the number
of shares outstanding of each of the issuer's classes of common stock, as of
the
latest practicable date:
|
OUTSTANDING
|
CLASS
|
AS
OF MAY 8, 2006
|
FirstEnergy
Corp., $.10 par value
|
329,836,276
|
Ohio
Edison
Company, no par value
|
100
|
Pennsylvania
Power Company, $30 par value
|
6,290,000
|
FirstEnergy
Corp. is
the sole holder of Ohio Edison Company common stock. Ohio Edison Company is
the
sole holder of Pennsylvania Power Company common stock.
This
combined Form
10-Q/A is separately filed by FirstEnergy Corp., Ohio Edison Company and
Pennsylvania Power 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/A
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, the continued
ability of our regulated utilities to collect transition and other charges
or to
recover increased transmission costs, maintenance costs being higher than
anticipated, legislative and regulatory changes (including revised environmental
requirements), and the legal and regulatory changes resulting from the
implementation of the Energy Policy Act of 2005 (including, but not limited
to,
the repeal of the Public Utility Holding Company Act of 1935), the uncertainty
of the timing and amounts of the capital expenditures (including that such
amounts could be higher than anticipated) or levels of emission reductions
related to the Consent Decree resolving the New Source Review litigation,
adverse regulatory or legal decisions and outcomes (including, but not limited
to, the revocation of necessary licenses or operating permits, fines or other
enforcement actions and remedies) of governmental investigations and oversight,
including by the Securities and Exchange Commission, the United States
Attorney’s Office, the Nuclear Regulatory Commission and the various state
public utility commissions as disclosed in the registrants' Securities and
Exchange Commission filings, generally, and with respect to the Davis-Besse
Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear Power
Plant in particular, the timing and outcome of various proceedings before the
Public Utilities Commission of Ohio and the Pennsylvania Public Utility
Commission, including the transition rate plan filings for Met-Ed and Penelec,
the continuing availability and operation of generating units, the ability
of
generating units to continue to operate at, or near full capacity, the inability
to accomplish or realize anticipated benefits from strategic goals (including
employee workforce initiatives), the anticipated benefits from voluntary pension
plan contributions, the ability to improve electric commodity margins and to
experience growth in the distribution business, the ability to access the public
securities and other capital markets and the cost of such capital, the outcome,
cost and other effects of present and potential legal and administrative
proceedings and claims related to the August 14, 2003 regional power
outage, circumstances which may lead management to seek, or the Board of
Directors to grant, in each case in its sole discretion, authority for the
implementation of a share repurchase program in the future, the risks and other
factors discussed from time to time in the registrants' Securities and Exchange
Commission filings, including their annual report on Form 10-K for the year
ended December 31, 2005, and other similar factors. Dividends declared from
time to time during any annual period may in aggregate vary from the indicated
amounts due to circumstances considered by the Board at the time of the actual
declarations. Also, a security rating should not be viewed as a recommendation
to buy, sell, or hold securities and it may be subject to revision or withdrawal
at any time. The registrants expressly disclaim any current intention to update
any forward-looking statements contained herein as a result of new information,
future events, or otherwise.
EXPLANATORY
NOTE
This
combined
Amendment No. 1 on Form 10-Q/A for the quarter ended March 31, 2006 for
FirstEnergy Corp., Ohio Edison Company and Pennsylvania Power Company is
being
filed to correct a misclassification in their respective Consolidated Statements
of Cash Flows for the three months ended March 31, 2006, contained in Part
I,
Item 1, Consolidated Financial Statements. This correction does not affect
the
respective registrants’ previously reported consolidated statements of income
and comprehensive income for the three months ended March 31, 2006 and
consolidated balance sheet as of March 31, 2006 contained in the combined
Form
10-Q for the quarter ended March 31, 2006, as originally filed on May 9,
2006.
Except for Part I, Items 1, 2 and 4 and certain exhibits under Part II, Item
6,
no other information included in the Form 10-Q as originally filed is being
revised by, or repeated in this amendment.
As
described in Note
1 to the consolidated financial statements of FirstEnergy Corp., Ohio Edison
Company and Pennsylvania Power Company, the registrants have restated their
respective consolidated statements of cash flows solely to correct a
misclassification of a $78 million cash receipt from the liquidation of
temporary cash investments at Pennsylvania Power Company for the quarter
ended
March 31, 2006. The cash receipt was previously reported in cash flows from
operating activities and should have been reported in cash flows from investing
activities. The reclassification has resulted in an approximately $78 million
decrease in the previously reported cash flows from operating activities,
a
corresponding increase in cash flows from investing activities and no effect
on
the previously reported net increase or decrease in cash and cash equivalents
in
each of the respective registrant’s consolidated statement of cash flows for the
three months ended March 31, 2006.
Please
note that the
information contained in this Amendment No. 1, including the consolidated
financial statements and notes thereto, does not reflect events occurring
after
the date of the original Form 10-Q filing, except to the extent described
above.
Such events include, among others, the events described in our reports under
the
Securities Exchange Act of 1934, as amended, filed with the SEC since May
9,
2006.
TABLE
OF
CONTENTS
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Pages
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Glossary
of Terms
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ii-iv
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Part
I. Financial
Information
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Items
1. and 2. - Financial Statements and Management’s Discussion and Analysis
of Results
of Operation and Financial Condition
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Notes
to
Consolidated Financial Statements
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1-26
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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27
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Consolidated
Statements of Comprehensive Income
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28
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Consolidated
Balance Sheets
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29
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|
Consolidated
Statements of Cash Flows
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30
|
|
Report
of
Independent Registered Public Accounting Firm
|
31
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|
Management's
Discussion and Analysis of Results of Operations and
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32-63
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|
Financial
Condition
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Ohio
Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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64
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Consolidated
Balance Sheets
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65
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Consolidated
Statements of Cash Flows
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66
|
|
Report
of
Independent Registered Public Accounting Firm
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67
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Management's
Discussion and Analysis of Results of Operations and
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68-79
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Financial
Condition
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Pennsylvania
Power Company
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Consolidated
Statements of
Income and Comprehensive Income
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80
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Consolidated
Balance
Sheets
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81
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|
Consolidated
Statements of
Cash Flows
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82
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|
Report
of
Independent Registered Public Accounting Firm
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83
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Management's
Discussion and Analysis of Results of Operations and
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84-91
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Financial
Condition
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Item
4. Controls
and Procedures
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92
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Part
II. Other
Information
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Item
6. Exhibits
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93
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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
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CEI
|
The
Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
|
Centerior
|
Centerior
Energy Corporation, former parent of CEI and TE, which merged with
OE to
form FirstEnergy on November 8, 1997.
|
CFC
|
Centerior
Funding Corporation, a wholly owned finance subsidiary of
CEI
|
Companies
|
OE,
CEI, TE,
Penn, JCP&L, Met-Ed and Penelec
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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., owns and operates non-nuclear generating
facilities
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FirstCom
|
First
Communications, LLC, provides local and long-distance telephone
service
|
FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
|
FSG
|
FirstEnergy
Facilities Services Group, LLC, the parent company of several heating,
ventilation, air
conditioning and energy management companies
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GPU
|
GPU,
Inc.,
former parent of JCP&L, Met-Ed and Penelec, which merged with
FirstEnergy on November 7,
2001
|
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
|
Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
|
MYR
|
MYR
Group,
Inc., a utility infrastructure construction service
company
|
NGC
|
FirstEnergy
Nuclear Generation Corp., owns nuclear generating
facilities
|
OE
|
Ohio
Edison
Company, an Ohio electric utility operating subsidiary
|
OE
Companies
|
OE
and
Penn
|
Ohio
Companies
|
CEI,
OE and
TE
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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
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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
|
|
|
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
25, "Accounting for Stock Issued to Employees"
|
APB
29
|
APB
Opinion
No. 29, "Accounting for Nonmonetary Transactions"
|
ARB
|
Accounting
Research Bulletin
|
ARB
43
|
ARB
No. 43,
"Restatement and Revision of Accounting Research
Bulletins"
|
ARO
|
Asset
Retirement Obligation
|
BGS
|
Basic
Generation Service
|
CAIDI
|
Customer
Average Interruption Duration Index
|
CAIR
|
Clean
Air
Interstate Rule
|
CAL
|
Confirmatory
Action Letter
|
CAMR
|
Clean
Air
Mercury Rule
|
CBP
|
Competitive
Bid Process
|
CO2 |
Carbon
Dioxide |
CTC
|
Competitive
Transition Charge
|
DOJ
|
United
States
Department of Justice
|
DRA
|
Division
of
the Ratepayer Advocate
|
ECAR
|
East
Central
Area Reliability Coordination Agreement
|
EITF
|
Emerging
Issues Task Force
|
EITF
04-13
|
EITF
Issue No.
04-13, “Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
|
EPA
|
Environmental
Protection Agency
|
EPACT
|
Energy
Policy
Act of 2005
|
GLOSSARY OF TERMS
Cont'd.
ERO
|
Electric
Reliability Organization
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy
Regulatory Commission
|
FIN
|
FASB
Interpretation
|
FIN
46R
|
FIN
46
(revised December 2003), "Consolidation of Variable Interest
Entities"
|
FIN
47
|
FIN
47,
"Accounting for Conditional Asset Retirement Obligations - an
interpretation of FASB Statement No. 143"
|
FMB
|
First
Mortgage
Bonds
|
GAAP
|
Accounting
Principles Generally Accepted in the United States
|
GCAF
|
Generation
Charge Adjustment Factor
|
GHG
|
Greenhouse
Gases
|
KWH
|
Kilowatt-hours
|
LOC
|
Letter
of
Credit
|
MEIUG
|
Met-Ed
Industrial Users Group
|
MISO
|
Midwest
Independent Transmission System Operator, Inc.
|
Moody’s
|
Moody’s
Investors Service
|
MOU
|
Memorandum
of
Understanding
|
MTC
|
Market
Transition Charge
|
MW
|
Megawatts
|
NAAQS
|
National
Ambient Air Quality Standards
|
NERC
|
North
American
Electric Reliability Council
|
NJBPU
|
New
Jersey
Board of Public Utilities
|
NOAC
|
Northwest
Ohio
Aggregation Coalition
|
NOV
|
Notices
of
Violation
|
NOx |
Nitrogen
Oxide |
NRC
|
Nuclear
Regulatory Commission
|
NUG
|
Non-Utility
Generation
|
NUGC
|
Non-Utility
Generation Charge
|
OCA
|
Office
of
Consumer Advocate
|
OCC
|
Office
of the
Ohio Consumers' Counsel
|
OCI
|
Other
Comprehensive Income
|
OPEB
|
Other
Post-Employment Benefits
|
OSBA
|
Office
of
Small Business Advocate
|
OTS
|
Office
of
Trial Staff
|
PCAOB
|
Public
Company
Accounting Oversight Board
|
PICA
|
Penelec
Industrial Customer Association
|
PJM
|
PJM
Interconnection L. L. C.
|
PLR
|
Provider
of
Last Resort
|
PPUC
|
Pennsylvania
Public Utility Commission
|
PRP
|
Potentially
Responsible Party
|
PUCO
|
Public
Utilities Commission of Ohio
|
PUHCA
|
Public
Utility
Holding Company Act of 1935
|
RCP
|
Rate
Certainty
Plan
|
RFP
|
Request
for
Proposal
|
RSP
|
Rate
Stabilization Plan
|
RTC
|
Regulatory
Transition Charge
|
RTO
|
Regional
Transmission Organization
|
S&P
|
Standard
&
Poor’s Ratings Service
|
SAIFI
|
System
Average
Interruption Frequency Index
|
SBC
|
Societal
Benefits Charge
|
SEC
|
U.S.
Securities and Exchange Commission
|
SFAS
|
Statement
of
Financial Accounting Standards
|
SFAS
123
|
SFAS
No. 123,
"Accounting for Stock-Based Compensation"
|
SFAS
123(R)
|
SFAS
No.
123(R), "Share-Based Payment"
|
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
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
155
|
SFAS
No. 155,
"Accounting for Certain Hybrid Financial Instruments - an amendment
of
FASB Statements
No.
133 and 140"
|
GLOSSARY OF TERMS
Cont'd.
SO2 |
Sulfur
Dioxide |
TBC
|
Transition
Bond Charge
|
TMI-1
|
Three
Mile
Island Unit 1
|
TMI-2
|
Three
Mile
Island Unit 2
|
VIE
|
Variable
Interest Entity
|
PART
I.
FINANCIAL INFORMATION
FIRSTENERGY
CORP. AND SUBSIDIARIES
OHIO
EDISON
COMPANY AND SUBSIDIARIES
PENNSYLVANIA
POWER COMPANY AND SUBSIDIARY
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. -
ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy’s
principal business 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. Penn is a
wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements
also include its other principal subsidiaries: FENOC, FES and its subsidiary
FGCO, NGC, FESC and FSG.
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 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 these
estimates. The reported results of operations are not indicative of results
of
operations for any future period.
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,
2005 for FirstEnergy and the Companies. 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 businesses divested
in
the first and second quarters of 2005 have been classified as discontinued
operations on the Consolidated Statements of Income (see Note 4). As discussed
in Note 13, interim period segment reporting in 2005 was reclassified to conform
with the current year business segment organizations and operations.
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. Intercompany transactions and balances are
eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9) when
it
is determined to be the VIE's primary beneficiary. Investments in
nonconsolidated affiliates over which FirstEnergy and its subsidiaries have
the
ability to exercise significant influence, but not control, (20-50 percent
owned
companies, joint ventures and partnerships) are accounted for under the equity
method. Under the equity method, the interest in the entity is reported as
an
investment in the Consolidated Balance Sheet and the percentage share of the
entity’s earnings is reported in the Consolidated Statement of Income. Certain
prior year amounts have been reclassified to conform to the current
presentation.
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 PCAOB. 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.
Restatement
of the Consolidated Statements of Cash Flows
FirstEnergy,
OE and
Penn are restating their respective Consolidated Statements of Cash Flows
for
the three months ended March 31, 2006. This corrects a misclassification
of a
cash receipt by Penn of $78 million from the liquidation of cash investments
(restricted cash related to the 2005 generation asset transfers) in the first
quarter of 2006. Penn is a subsidiary of OE, which is a direct subsidiary
of
FirstEnergy. This correction also resulted in the restatement of FirstEnergy’s
and OE’s consolidated statements of cash flows. The cash receipt was previously
reported under “Prepayments and other current assets” in cash flows from
operating activities for the quarter ended March 31, 2006 and should have
been
reported under “Cash Investments” for FirstEnergy, OE and Penn in cash flows
from investing activities for the quarter ended March 31, 2006. This
reclassification resulted in a $78 million decrease in the previously reported
cash flows from operating activities and a corresponding increase in cash
flows
provided from (used for) investing activities in FirstEnergy’s, OE’s and Penn’s
consolidated statements of cash flows for the three months ended March 31,
2006.
This correction does not change their previously reported consolidated
statements of income and comprehensive income for the three months ended
March
31, 2006, their consolidated balance sheets as of March 31, 2006 or the net
increase or decrease in cash and cash equivalents for the three months ended
March 31, 2006 in their respective statements of cash flows.
The
effect of this
correction on FirstEnergy’s, OE’s and Penn’s Consolidated Statements of Cash
Flows for the three months ended March 31, 2006 are as
follows:
The
effect of this
correction on FirstEnergy’s, OE’s and Penn’s Consolidated Statements of Cash
Flows for the three months ended March 31, 2006 are as follows:
FIRSTENERGY
|
|
Three
Months Ended
|
|
|
|
March
31, 2006
|
|
|
|
|
|
As
Previously
|
|
As
|
|
|
|
|
|
Reported
|
|
Restated
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
221
|
|
$
|
221
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
|
|
148
|
|
|
148
|
|
Amortization
of regulatory assets
|
|
|
|
|
|
222
|
|
|
222
|
|
Deferral
of
new regulatory assets
|
|
|
|
|
|
(59
|
)
|
|
(59
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
|
|
|
20
|
|
|
20
|
|
Deferred
purchased power and other costs
|
|
|
|
|
|
(125
|
)
|
|
(125
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
|
|
|
6
|
|
|
6
|
|
Deferred
rents
and lease market valuation liability
|
|
|
|
|
|
(38
|
)
|
|
(38
|
)
|
Accrued
compensation and retirement benefits
|
|
|
|
|
|
(19
|
)
|
|
(19
|
)
|
Commodity
derivative transactions, net
|
|
|
|
|
|
26
|
|
|
26
|
|
Cash
collateral
|
|
|
|
|
|
(106
|
)
|
|
(106
|
)
|
Decrease
(Increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
|
|
|
226
|
|
|
226
|
|
Materials
and
supplies
|
|
|
|
|
|
(52
|
)
|
|
(52
|
)
|
Prepayments
and other current assets
|
|
|
|
|
|
(15
|
)
|
|
(93
|
)
|
Increase
(Decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
|
|
|
(114
|
)
|
|
(114
|
)
|
Accrued
taxes
|
|
|
|
|
|
8
|
|
|
8
|
|
Accrued
interest
|
|
|
|
|
|
100
|
|
|
100
|
|
Electric
service prepayment programs
|
|
|
|
|
|
(14
|
)
|
|
(14
|
)
|
Other
|
|
|
|
|
|
(33
|
)
|
|
(33
|
)
|
Net
cash
provided from operating activities
|
|
|
|
|
|
402
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
(50
|
)
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
|
|
|
(447
|
)
|
|
(447
|
)
|
Proceeds
from
asset sales
|
|
|
|
|
|
57
|
|
|
57
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
|
|
|
481
|
|
|
481
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
|
|
|
(484
|
)
|
|
(484
|
)
|
Cash
investments
|
|
|
|
|
|
25
|
|
|
103
|
|
Other
|
|
|
|
|
|
(20
|
)
|
|
(20
|
)
|
Net
cash used
for investing activities
|
|
|
|
|
|
(388
|
)
|
|
(310
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
decrease
in cash and cash equivalents
|
|
|
|
|
$
|
(36
|
)
|
$
|
(36
|
)
|
|
|
|
|
|
|
|
|
|
|
|
OE
|
|
Three
Months Ended
|
|
|
|
March
31, 2006
|
|
|
|
|
|
As
Previously
|
|
As
|
|
|
|
|
|
Reported
|
|
Restated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
63,830
|
|
|
|
|
$
|
63,830
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
|
|
18,016
|
|
|
|
|
|
18,016
|
|
Amortization
of regulatory assets
|
|
|
|
|
|
53,861
|
|
|
|
|
|
53,861
|
|
Deferral
of
new regulatory assets
|
|
|
|
|
|
(25,606
|
)
|
|
|
|
|
(25,606
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
|
|
|
532
|
|
|
|
|
|
532
|
|
Deferred
purchased power costs
|
|
|
|
|
|
(10,634
|
)
|
|
|
|
|
(10,634
|
)
|
Amortization
of lease costs
|
|
|
|
|
|
32,934
|
|
|
|
|
|
32,934
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
|
|
|
(3,945
|
)
|
|
|
|
|
(3,945
|
)
|
Accrued
compensation and retirement benefits
|
|
|
|
|
|
(1,494
|
)
|
|
|
|
|
(1,494
|
)
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
|
|
|
116,271
|
|
|
|
|
|
116,271
|
|
Prepayments
and other current assets
|
|
|
|
|
|
66,112
|
|
|
|
|
|
(12,136
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
|
|
|
9,668
|
|
|
|
|
|
9,668
|
|
Accrued
taxes
|
|
|
|
|
|
27,505
|
|
|
|
|
|
27,505
|
|
Accrued
interest
|
|
|
|
|
|
3,721
|
|
|
|
|
|
3,721
|
|
Electric
service prepayment programs
|
|
|
|
|
|
(7,763
|
)
|
|
|
|
|
(7,763
|
)
|
Other
|
|
|
|
|
|
3,922
|
|
|
|
|
|
3,922
|
|
Net
cash
provided from operating activities
|
|
|
|
|
|
346,930
|
|
|
|
|
|
268,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
(273,881
|
)
|
|
|
|
|
(273,881
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
|
|
|
(28,793
|
)
|
|
|
|
|
(28,793
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
|
|
|
19,054
|
|
|
|
|
|
19,054
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
|
|
|
(19,054
|
)
|
|
|
|
|
(19,054
|
)
|
Loans
to
associated companies, net
|
|
|
|
|
|
(45,224
|
)
|
|
|
|
|
(45,224
|
)
|
Cash
investments
|
|
|
|
|
|
-
|
|
|
|
|
|
78,248
|
|
Other
|
|
|
|
|
|
1,087
|
|
|
|
|
|
1,087
|
|
Net
cash
provided (used for) investing activities
|
|
|
|
|
|
(72,930
|
)
|
|
|
|
|
5,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase in cash and cash equivalents
|
|
|
|
|
$
|
119
|
|
|
|
|
|
119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PENN
|
Three
Months Ended
|
|
|
March
31, 2006
|
|
|
|
|
As
Previously
|
|
As
|
|
|
|
|
Reported
|
|
Restated
|
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
|
|
$
|
746
|
|
$
|
746
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
|
2,431
|
|
|
2,431
|
|
Amortization
of regulatory assets
|
|
|
|
|
3,411
|
|
|
3,411
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
|
|
(2,348
|
)
|
|
(2,348
|
)
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
|
|
41,950
|
|
|
41,950
|
|
Prepayments
and other current assets
|
|
|
|
|
64,433
|
|
|
(13,815
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
|
|
(53,068
|
)
|
|
(53,068
|
)
|
Accrued
taxes
|
|
|
|
|
4,175
|
|
|
4,175
|
|
Accrued
interest
|
|
|
|
|
(819
|
)
|
|
(819
|
)
|
Other
|
|
|
|
|
1,607
|
|
|
1,607
|
|
Net
cash
provided from (used for) operating activities
|
|
|
|
|
62,518
|
|
|
(15,730
|
)
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
(48,321
|
)
|
|
(48,321
|
)
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
|
|
(5,114
|
)
|
|
(5,114
|
)
|
Loans
to
associated companies
|
|
|
|
|
(9,010
|
)
|
|
(9,010
|
)
|
Cash
investments
|
|
|
|
|
-
|
|
|
78,248
|
|
Other
|
|
|
|
|
(56
|
)
|
|
(56
|
)
|
Net
cash
provided from (used for) investing activities
|
|
|
|
|
(14,180
|
)
|
|
64,068
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
|
$
|
17
|
|
$
|
17
|
|
|
|
|
|
|
|
|
|
|
|
2.
-
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 other agreements to issue common stock were exercised.
Stock-based awards to purchase 0.5 million shares of common stock in the
three months ended March 31, 2005 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. No
stock-based awards were excluded from the calculation in the three months ended
March 31, 2006. The following table reconciles the denominators for basic
and diluted earnings per share from Income Before Discontinued Operations:
|
|
Three
Months Ended
|
|
Reconciliation
of Basic and Diluted
|
|
March
31,
|
|
Earnings
per Share
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Income
Before
Discontinued Operations
|
|
$
|
221
|
|
$
|
141
|
|
|
|
|
|
|
|
|
|
Average
Shares
of Common Stock Outstanding:
|
|
|
|
|
|
|
|
Denominator
for basic earnings per share
|
|
|
|
|
|
|
|
(weighted
average shares outstanding)
|
|
|
329
|
|
|
328
|
|
|
|
|
|
|
|
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
1
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Denominator
for diluted earnings per share
|
|
|
330
|
|
|
329
|
|
|
|
|
|
|
|
|
|
Income
Before
Discontinued Operations per common share:
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.67
|
|
$
|
0.43
|
|
Diluted
|
|
$
|
0.67
|
|
$
|
0.42
|
|
3.
-
GOODWILL
FirstEnergy's
goodwill primarily relates to its regulated services segment. In the three
months ended March 31, 2006, FirstEnergy adjusted goodwill related to the
divestiture of a non-core asset (60% interest in MYR), a successful tax claim
relating to the former Centerior companies, and an adjustment to the former
GPU
companies due to the realization of a tax benefit that had been reserved in
purchase accounting.
A
summary of the
changes in goodwill for the three months ended March 31, 2006 is shown
below:
|
|
FirstEnergy
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance
as of
January 1, 2006
|
|
$
|
6,010
|
|
$
|
1,689
|
|
$
|
501
|
|
$
|
1,986
|
|
$
|
864
|
|
$
|
882
|
|
Non-core
assets sale
|
|
|
(53
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
related to Centerior acquisition
|
|
|
(1
|
)
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
related to GPU acquisition
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
(8
|
)
|
|
(4
|
)
|
|
(4
|
)
|
Balance
as of
March 31, 2006
|
|
$
|
5,940
|
|
$
|
1,688
|
|
$
|
501
|
|
$
|
1,978
|
|
$
|
860
|
|
$
|
878
|
|
4.
-
DIVESTITURES AND DISCONTINUED OPERATIONS
In
March 2006,
FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2
million. As a result, FirstEnergy deconsolidated MYR and began accounting for
its remaining 40% interest under the equity method.
In March 2005, FES sold its retail natural gas business for an after-tax gain
of
$5 million and FirstEnergy sold 51% of its interest in FirstCom for an
after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85%
interest in FirstCom under the equity method.
FirstEnergy
sold two FSG subsidiaries (Elliott-Lewis and Spectrum) and an MYR subsidiary
(Power Piping Company) in the first quarter of 2005, resulting in aggregate
after-tax gains of $12 million. The remaining FSG subsidiaries continue to
be
actively marketed and qualify as assets held for sale in accordance with
SFAS 144. Management anticipates that the transfer of FSG assets, with a
net carrying value of $49 million as of March 31, 2006, will qualify
for recognition as completed sales within one year. As of March 31, 2006,
the FSG subsidiaries classified as held for sale did not meet the criteria
for
discontinued operations. The carrying amounts of FSG's assets and liabilities
held for sale are not material and have not been classified as assets held
for
sale on FirstEnergy's Consolidated Balance Sheets. See Note 13 for FSG's
segment financial information.
Net
income (including the
gain on sales discussed above) for Elliott-Lewis, Power Piping, FES' natural
gas
business and Cranston (sold in the second quarter of 2005) of $19 million for
the first quarter of 2005 is reported as discontinued operations on
FirstEnergy's Consolidated Statements of Income. Pre-tax operating results
for
these entities were $4 million for the first quarter of 2005. Revenues
associated with discontinued operations for the first quarter of 2005 were
$195
million. The following table summarizes the sources of income from discontinued
operation for the three months ended March 31, 2005:
|
|
(In
millions)
|
|
Discontinued
Operations (Net of tax)
|
|
|
|
Gain
on
sale:
|
|
|
|
Natural
gas
business
|
|
$
|
5
|
|
FSG
subsidiaries and Power Piping
|
|
|
12
|
|
Reclassification
of operating income
|
|
|
2
|
|
Total
|
|
$
|
19
|
|
5.
-
DERIVATIVE INSTRUMENTS
FirstEnergy
is
exposed to financial risks resulting from the fluctuation of interest rates
and
commodity prices, including prices for electricity, natural gas, coal and energy
transmission. 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. FirstEnergy’s Risk Policy Committee, comprised
of members of senior management, provides general management oversight to risk
management activities throughout the Company. They are responsible for promoting
the effective design and implementation of sound risk management programs.
They
also oversee compliance with corporate risk management policies and established
risk management practices.
FirstEnergy
accounts
for derivative instruments on its Consolidated Balance Sheet at their fair
value
unless they meet the normal purchase and normal sales criteria. Derivatives
that
meet that criterion are accounted for on the accrual basis. The changes in
the
fair value of derivative instruments that do not meet the normal purchase and
sales criteria are recorded in current earnings, in AOCL, or as part of the
value of the hedged item, depending on whether or not it is designated as part
of a hedge transaction, the nature of the hedge transaction and hedge
effectiveness.
FirstEnergy
hedges
anticipated transactions using cash flow hedges. Such transactions include
hedges of anticipated electricity and natural gas purchases and anticipated
interest payments associated with future debt issues. The effective portion
of
such hedges are initially recorded in equity as other comprehensive income
or
loss and are subsequently included in net income as the underlying hedged
commodities are delivered or interest payments are made. Gains and losses from
any ineffective portion of cash flow hedges are included directly in earnings.
The
net deferred
losses of $53 million included in AOCL as of March 31, 2006, for derivative
hedging activity, as compared to the December 31, 2005 balance of $78
million of net deferred losses, resulted from a $19 million decrease
related to current hedging activity and a $6 million decrease due to net hedge
losses included in earnings during the three months ended March 31, 2006.
Approximately $11 million (after tax) of the net deferred losses on derivative
instruments in AOCL as of March 31, 2006 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.
FirstEnergy
has
entered into swaps that have been designated as fair value hedges of fixed-rate,
long-term debt issues to protect 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. During the first quarter of 2006,
FirstEnergy unwound swaps with a total notional amount of $350 million for
which it paid $1 million in cash. The losses will be recognized in earnings
over the remaining maturity of each respective hedged security as increased
interest expense. As of March 31, 2006, the aggregate notional value of
interest rate swap agreements outstanding was $750 million.
During
2005 and the
first quarter of 2006, FirstEnergy entered into several forward starting swap
agreements (forward swaps) in order to hedge a portion of the consolidated
interest rate risk associated with the anticipated issuances of fixed-rate,
long-term debt securities for one or more of its consolidated entities during
2006 - 2008 as outstanding debt matures. These derivatives are treated as cash
flow hedges, protecting against the risk of changes in future interest payments
resulting from changes in benchmark U.S. Treasury rates between the date of
hedge inception and the date of the debt issuance. During the first quarter
of
2006, FirstEnergy revised its financing plan related to forward swaps with
an
aggregate notional amount of $500 million, impacting the term and timing of
the
respective issuances. As required by SFAS 133, FirstEnergy de-designated the
forward swaps and assessed the amount of ineffectiveness. FirstEnergy terminated
the forward swaps and received cash of $16 million, of which approximately
$5 million ($3 million net of tax) was deemed ineffective and recognized in
earnings in the first quarter of 2006. The remaining gain deemed effective
in
the amount of approximately $11 million ($7 million net of tax) was recorded
in
other comprehensive income and will subsequently be recognized in earnings
over
the terms of the respective forward swaps. As of March 31, 2006,
FirstEnergy had forward swaps with an aggregate notional amount of
$1 billion and a fair value of $25 million.
6.
- STOCK
BASED COMPENSATION
FirstEnergy
has the
following stock-based compensation programs: Long-term Incentive Program (LTIP);
Executive Deferred Compensation Plan (EDCP); Employee Stock Ownership Plan
(ESOP) and Deferred Compensation Plan for Outside Directors (DCPD), which were
previously accounted for under the recognition and measurement principles of
APB
25 and related interpretations. The LTIP includes four stock-based compensation
programs - restricted stock, restricted stock units, stock options, and
performance shares.
Effective
January 1,
2006, FirstEnergy adopted SFAS 123(R), which requires the expensing of
stock-based compensation. Under SFAS 123(R), all share-based compensation cost
is measured at the grant date, based on the fair value of the award and is
recognized as an expense over the employee’s requisite service period.
FirstEnergy adopted the modified prospective method, under which compensation
expense recognized in the first quarter of 2006 includes the expense for all
share-based payments granted prior to but not yet vested as of January 1,
2006. Results for prior periods have not been restated.
Under
APB 25, no
compensation expense was reflected in net income for stock options 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. The pro-forma effects on net income for stock
options were instead disclosed in a footnote to the financial statements. Under
APB 25 and SFAS 123(R) expense was recorded in the income statement for
restricted stock, restricted stock units, performance shares and the EDCP and
DCPD programs. No stock options have been issued subsequent to the third quarter
of 2004. Consequently, the impact of adopting SFAS 123(R) was not material
to
FirstEnergy's net income and earnings per share in the first quarter 2006.
In
the year of adoption all disclosures prescribed by SFAS 123(R) are required
to
be included in both the quarterly Form 10-Q filings as well as the annual Form
10-K filing. However, due to the immaterial impact of the adoption of SFAS
123(R) on FirstEnergy's financial results, only condensed disclosure has been
provided. For annual disclosures see FirstEnergy's 2005 Form 10-K.
The
following table
illustrates the effect on net income and earnings per share for the first
quarter of 2005, as if FirstEnergy had adopted SFAS 123(R) as of January 1,
2005
(in millions):
|
|
March
31, 2005
|
|
Net
Income, as
reported
|
|
$
|
160
|
|
|
|
|
|
|
|
|
|
|
|
Add
back
compensation expense
|
|
|
|
|
reported
in
net income, net of tax (based on
|
|
|
8
|
|
APB
25)*
|
|
|
|
|
|
|
|
|
|
Deduct
compensation expense based
|
|
|
|
|
upon
estimated
fair value, net of tax*
|
|
|
(11
|
)
|
|
|
|
|
|
Pro
forma net
income
|
|
$
|
157
|
|
Earnings
Per
Share of Common Stock -
|
|
|
|
|
Basic
|
|
|
|
|
As
Reported
|
|
$
|
0.49
|
|
Pro
Forma
|
|
$
|
0.48
|
|
Diluted
|
|
|
|
|
As
Reported
|
|
$
|
0.48
|
|
Pro
Forma
|
|
$
|
0.48
|
|
* Includes
restricted
stock, restricted stock units, stock options, performance
shares,
ESOP, EDCP
and DCPD.
7.
- ASSET
RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations under SFAS 143 for
nuclear power plant decommissioning, reclamation of a sludge disposal pond
and
closure of two coal ash disposal sites. In addition, FirstEnergy has recognized
conditional retirement obligations (primarily for asbestos remediation) in
accordance with FIN 47, which was implemented on December 31, 2005. Had FIN
47 been applied in the first quarter of 2005, the impact on earnings would
have
been immaterial.
The ARO liability of $1.1 billion as of March 31, 2006 primarily related to
the
nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2
nuclear generating facilities. 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 to measure the fair value
of
the nuclear decommissioning ARO.
FirstEnergy
maintains nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of March 31, 2006,
the fair value of the decommissioning trust assets was
$1.8 billion.
The following tables analyze changes to the ARO balance during the first
quarters of 2006 and 2005, respectively.
ARO
Reconciliation
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
Penn
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance,
January 1, 2006
|
|
$
|
1,126
|
|
$
|
83
|
|
$
|
8
|
|
$
|
25
|
|
$
|
-
|
|
$
|
80
|
|
$
|
142
|
|
$
|
72
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated cash flows
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
March
31, 2006
|
|
$
|
1,148
|
|
$
|
84
|
|
$
|
8
|
|
$
|
25
|
|
$
|
-
|
|
$
|
81
|
|
$
|
144
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2005
|
|
$
|
1,078
|
|
$
|
201
|
|
$
|
272
|
|
$
|
194
|
|
$
|
138
|
|
$
|
73
|
|
$
|
133
|
|
$
|
66
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
17
|
|
|
3
|
|
|
4
|
|
|
3
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated cash flows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
March
31, 2005
|
|
$
|
1,095
|
|
$
|
204
|
|
$
|
276
|
|
$
|
197
|
|
$
|
140
|
|
$
|
75
|
|
$
|
135
|
|
$
|
67
|
|
8.
- PENSION
AND OTHER POSTRETIREMENT BENEFITS:
FirstEnergy
provides
noncontributory defined benefit pension plans that cover substantially all
of
its employees. The trusteed plans provide defined benefits based on years of
service and compensation levels. FirstEnergy also provides a minimum amount
of
noncontributory life insurance to retired employees in addition to optional
contributory insurance. Health care benefits, which include certain employee
contributions, deductibles and co-payments, are available upon retirement to
employees hired prior to January 1, 2005, their dependents and, under
certain circumstances, their survivors. FirstEnergy recognizes the expected
cost
of providing other postretirement benefits to employees, their beneficiaries
and
covered dependents from the time employees are hired until they become eligible
to receive those benefits.
The components of FirstEnergy's net periodic pension cost and other
postretirement benefit cost (including amounts capitalized) for the three months
ended March 31, 2006 and 2005, consisted of the following:
|
|
Pension
Benefits
|
|
Other
Postretirement Benefits
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
millions)
|
|
|
|
Service
cost
|
|
$
|
21
|
|
$
|
19
|
|
$
|
9
|
|
$
|
10
|
|
Interest
cost
|
|
|
66
|
|
|
64
|
|
|
26
|
|
|
28
|
|
Expected
return on plan assets
|
|
|
(99
|
)
|
|
(86
|
)
|
|
(12
|
)
|
|
(11
|
)
|
Amortization
of prior service cost
|
|
|
2
|
|
|
2
|
|
|
(19
|
)
|
|
(11
|
)
|
Recognized
net
actuarial loss
|
|
|
15
|
|
|
9
|
|
|
14
|
|
|
10
|
|
Net
periodic
cost
|
|
$
|
5
|
|
$
|
8
|
|
$
|
18
|
|
$
|
26
|
|
Pension
and
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. The Companies capitalize employee benefits
related to construction projects. The net periodic pension costs (credits)
and
net periodic postretirement benefit costs (including amounts capitalized)
recognized by each of the Companies for the three months ended March 31,
2006 and 2005 were as follows:
|
|
Pension
Benefit Cost (Credit)
|
|
Other
Postretirement
Benefit
Cost
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
millions)
|
|
|
|
OE
|
|
$
|
(1.1
|
)
|
$
|
0.2
|
|
$
|
3.4
|
|
$
|
5.8
|
|
Penn
|
|
|
(0.4
|
)
|
|
(0.2
|
)
|
|
0.8
|
|
|
1.2
|
|
CEI
|
|
|
1.0
|
|
|
0.3
|
|
|
2.8
|
|
|
3.8
|
|
TE
|
|
|
0.2
|
|
|
0.3
|
|
|
2.0
|
|
|
2.2
|
|
JCP&L
|
|
|
(1.4
|
)
|
|
(0.2
|
)
|
|
0.6
|
|
|
2.7
|
|
Met-Ed
|
|
|
(1.7
|
)
|
|
(1.1
|
)
|
|
0.7
|
|
|
0.4
|
|
Penelec
|
|
|
(1.3
|
)
|
|
(1.3
|
)
|
|
1.8
|
|
|
1.9
|
|
Other
FirstEnergy subsidiaries
|
|
|
9.9
|
|
|
9.5
|
|
|
6.1
|
|
|
8.1
|
|
|
|
$
|
5.2
|
|
$
|
7.5
|
|
$
|
18.2
|
|
$
|
26.1
|
|
9.
-
VARIABLE INTEREST ENTITIES
FIN
46R addresses
the consolidation of VIEs, including special-purpose entities, that are not
controlled through voting interests or in which the equity investors do not
bear
the entity's residual economic risks and rewards. FirstEnergy and its
subsidiaries consolidate VIEs when they are determined to be the VIE's primary
beneficiary as defined by FIN 46R.
Leases
FirstEnergy’s
consolidated financial statements include PNBV and Shippingport, VIEs created
in
1996 and 1997, respectively, to refinance debt originally issued in connection
with the 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 in connection with
OE’s 1987 sale and leaseback of 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 3% equity interest by an unaffiliated third
party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary
of OE. Shippingport was established to purchase all of the lease obligation
bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and
leaseback transaction in 1987. CEI and TE used debt and available funds to
purchase the notes issued by Shippingport.
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 under these
provisions 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
$666 million, $96 million and $535 million, respectively, that would
not be payable if the casualty value payments are made.
Power
Purchase Agreements
In
accordance with
FIN 46R, FirstEnergy 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 the Companies and the contract price for
power is correlated with the plant’s variable costs of production. FirstEnergy,
through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately
30 long-term power purchase agreements with NUG entities. The agreements were
entered into 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 eight of these entities, neither JCP&L, Met-Ed
nor 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 eight
entities, which sell their output at variable prices that correlate to some
extent with the operating costs of the plants. As required by FIN 46R,
FirstEnergy periodically requests from these eight entities the information
necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or
Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the
requested information, which in most cases was deemed by the requested entity
to
be proprietary. As such, FirstEnergy applied the scope exception that exempts
enterprises unable to obtain the necessary information to evaluate entities
under FIN 46R.
Since
FirstEnergy
has no equity or debt interests in the NUG entities, its maximum exposure to
loss relates primarily to the above-market costs it incurs for power. As of
March 31, 2006, the net projected above-market loss liability recognized
for these eight NUG agreements was $102 million. Purchased power costs from
these entities during the first quarters of 2006 and 2005 are shown in the
table
below:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
JCP&L
|
|
$
|
15
|
|
$
|
21
|
|
Met-Ed
|
|
|
16
|
|
|
16
|
|
Penelec
|
|
|
8
|
|
|
7
|
|
|
|
$
|
39
|
|
$
|
44
|
|
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.
10.
-
COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A)
GUARANTEES
AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various
agreements on behalf of its subsidiaries to provide financial or performance
assurances to third parties. These agreements include contract guarantees,
surety bonds and LOCs. As of March 31, 2006, outstanding guarantees and
other assurances totaled approximately $3.3 billion -- contract guarantees
($1.8 billion), surety bonds ($0.2 billion) and LOCs
($1.3 billion).
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved
in
energy commodity 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 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 is remote
that
such parental guarantees of $0.9 billion (included in the $1.8 billion discussed
above) as of March 31, 2006 would increase amounts otherwise payable by
FirstEnergy to meet its obligations incurred in connection with financings
and
ongoing energy and energy-related activities.
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 posting of cash
collateral or provision of an LOC may be required of the subsidiary. As of
March 31, 2006, FirstEnergy's maximum exposure under these collateral
provisions was $456 million.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of $136
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.
The
Companies, with the exception of TE and JCP&L, each have a wholly owned
subsidiary whose borrowings are secured by customer accounts receivable
purchased from its respective parent company. The CEI subsidiary's borrowings
are also secured by customer accounts receivable purchased from TE. Each
subsidiary company has its own receivables financing arrangement and, as a
separate legal entity with separate creditors, would have to satisfy its
obligations to creditors before any of its remaining assets could be available
to its parent company.
|
|
|
|
Borrowing
|
|
Subsidiary
Company
|
|
Parent
Company
|
|
Capacity
|
|
|
|
|
|
(In
millions)
|
|
OES
Capital,
Incorporated
|
|
|
OE
|
|
$
|
170
|
|
Centerior
Funding Corp.
|
|
|
CEI
|
|
|
200
|
|
Penn
Power
Funding LLC
|
|
|
Penn
|
|
|
25
|
|
Met-Ed
Funding
LLC
|
|
|
Met-Ed
|
|
|
80
|
|
Penelec
Funding LLC
|
|
|
Penelec
|
|
|
75
|
|
|
|
|
|
|
$
|
550
|
|
FirstEnergy
has also
guaranteed the obligations of the operators of the TEBSA project, 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 also provided an LOC ($36 million as of
March 31, 2006), which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA.
(B) 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 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 compliance with
existing regulations but is unable to predict future changes in regulatory
policies and what, if any, the effects of such changes would be. FirstEnergy
estimates additional capital expenditures for environmental compliance of
approximately $1.8 billion for 2006 through 2010.
The
Companies accrue
environmental liabilities only when they conclude that it is probable that
they
have an obligation for such costs and can reasonably estimate 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.
On
December 1, 2005,
FirstEnergy issued a comprehensive report to shareholders regarding air
emissions regulations and an assessment of its future risks and mitigation
efforts.
Clean
Air Act
Compliance
FirstEnergy
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 $32,500 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. FirstEnergy
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.
FirstEnergy
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
FirstEnergy's 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.
FirstEnergy believes its facilities are also complying with the NOX
budgets established
under State Implementation Plans 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 March 10, 2005, the EPA finalized the CAIR covering
a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania)
and
the District of Columbia based on proposed findings that air emissions from
28
eastern states and the District of Columbia significantly contribute to
non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS
in other states. CAIR provides each affected state until 2006 to develop
implementing regulations to achieve additional reductions of NOX
and SO2
emissions in two
phases (Phase I in 2009 for NOx,
2010 for
SO2
and Phase II in
2015 for both NOX
and SO2).
FirstEnergy's
Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
subject to caps on SO2
and NOx
emissions, whereas
its New Jersey fossil-fired generation facilities will be subject to only a
cap
on NOX
emissions.
According to the EPA, SO2
emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the
rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2
emissions in
affected states to just 2.5 million tons annually. NOx
emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the
rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOX
cap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on how they are ultimately implemented by the states
in which FirstEnergy operates 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 March 14, 2005, the EPA
finalized the CAMR, which provides a cap-and-trade program to reduce mercury
emissions from coal-fired power plants in two phases. Initially, mercury
emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit"
from implementation of SO2
and NOX
emission caps under
the EPA's CAIR program). Phase II of the mercury cap-and-trade program will
cap
nationwide mercury emissions from coal-fired power plants at 15 tons per
year by 2018. However, the final rules give states substantial discretion in
developing rules to implement these programs. In addition, both the CAIR and
the
CAMR have been challenged in the United States Court of Appeals for the District
of Columbia. FirstEnergy's future cost of compliance with these regulations
may
be substantial and will depend on how they are ultimately implemented by the
states in which FirstEnergy operates affected facilities.
The
model rules for
both CAIR and CAMR contemplate an input-based methodology to allocate allowances
to affected facilities. Under this approach, allowances would be allocated
based
on the amount of fuel consumed by the affected sources. FirstEnergy would prefer
an output-based generation-neutral methodology in which allowances are allocated
based on megawatts of power produced. Since this approach is based on output,
new and non-emitting generating facilities, including renewables and nuclear,
would be entitled to their proportionate share of the allowances. Consequently,
FirstEnergy would be disadvantaged if these model rules were implemented because
its substantial reliance on non-emitting (largely nuclear) generation is not
recognized under the input-based allocation.
W.
H. Sammis
Plant
In
1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities alleging violations
of
the Clean Air Act based on operation and maintenance of 44 power plants,
including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
In addition, the DOJ filed eight civil complaints against various investor-owned
utilities, including 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. On March 18, 2005, OE and Penn announced that they had
reached a settlement with the EPA, the DOJ and three states (Connecticut, New
Jersey, and New York) that resolved all issues related to the W. H. Sammis
Plant
New Source Review litigation. This settlement agreement was approved by the
Court on July 11, 2005, and requires reductions of NOX
and SO2
emissions at the
W. H. Sammis Plant and other coal fired plants through the installation of
pollution control devices and provides for stipulated penalties for failure
to
install and operate such pollution controls in accordance with that agreement.
Consequently, if FirstEnergy fails to install such pollution control devices,
for any reason, including, but not limited to, the failure of any third-party
contractor to timely meet its delivery obligations for such devices, FirstEnergy
could be exposed to penalties under the settlement agreement. Capital
expenditures necessary to meet those requirements are currently estimated to
be
$1.5 billion (the primary portion of which is expected to be spent in the
2008 to 2011 time period). On August 26, 2005, FGCO entered into an
agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will
engineer, procure, and construct air quality control systems for the reduction
of sulfur dioxide emissions. The settlement agreement also requires OE and
Penn
to spend up to $25 million toward environmentally beneficial projects,
which include wind energy purchased power agreements over a 20-year term. OE
and
Penn agreed to pay a civil penalty of $8.5 million. Results for the first
quarter of 2005 included the penalties paid by OE and Penn of $7.8 million
and $0.7 million, respectively. OE and Penn also recognized liabilities in
the first quarter of 2005 of $9.2 million and $0.8 million,
respectively, for probable future cash contributions toward environmentally
beneficial projects.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and
2012. The United States signed the Kyoto Protocol in 1998 but it failed to
receive the two-thirds vote required for ratification by the United States
Senate. However, the Bush administration has committed the United States to
a
voluntary climate change strategy to reduce domestic GHG intensity - the ratio
of emissions to economic output - by 18% through 2012. The EPACT established
a
Committee on Climate Change Technology to coordinate federal climate change
activities and promote the development and deployment of GHG reducing
technologies.
FirstEnergy
cannot
currently estimate the financial impact of climate change policies, although
the
potential restrictions on CO2
emissions could
require significant capital and other expenditures. The CO2
emissions per
kilowatt-hour of electricity generated by FirstEnergy is lower than many
regional competitors due to its diversified generation sources, which include
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 FirstEnergy's plants. In addition, Ohio,
New Jersey and Pennsylvania have water quality standards applicable to
FirstEnergy's 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.
On
September 7,
2004, the EPA established new performance standards under Section 316(b) of
the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality, when aquatic organisms
are pinned against screens or other parts of a cooling water intake system
and
entrainment, which occurs when aquatic species are drawn into a facility's
cooling water system. FirstEnergy is conducting comprehensive demonstration
studies, due in 2008, to determine the operational measures, equipment or
restoration activities, if any, necessary for compliance by its facilities
with
the performance standards. FirstEnergy is unable to predict the outcome of
such
studies. Depending on the outcome of such studies, the future cost of compliance
with these standards may require material capital expenditures.
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 are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
March 31, 2006, based on estimates of the total costs of cleanup, the
Companies' proportionate responsibility for such costs and the financial ability
of other unaffiliated 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. Total
liabilities of
approximately $63 million (JCP&L -
$47.3 million, CEI
-
$1.7 million, TE
-
$0.2 million,
Met-Ed -
$0.05 million
and other -
$13.7 million)
have been accrued through March 31, 2006.
(C) OTHER
LEGAL
PROCEEDINGS
Power
Outages
and Related Litigation
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 of
New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
In
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 product 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 Division 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 JCP&L transformers in Red Bank, New
Jersey. On September 8, 2004, the New Jersey Supreme Court denied the
motions filed by plaintiffs and JCP&L for leave to appeal the decision of
the Appellate Division. In December, 2005, JCP&L argued its motion for
summary judgment before the New Jersey Superior Court on its renewed motion
to
decertify the class and on remaining plaintiffs' negligence and breach of
contract claims. These motions remain pending. FirstEnergy is unable to predict
the outcome of these matters and no liability has been accrued as of
March 31, 2006.
On
August 14,
2003, various states and parts of southern Canada experienced widespread power
outages. The outages affected approximately 1.4 million customers in
FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages concluded, among other things, that
the problems leading to the outages began in FirstEnergy’s Ohio service area.
Specifically,
the
final report concluded, among other things, that the initiation of the
August 14, 2003 power outages resulted from 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 real-time 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 14, 2003 power
outages and that it does not adequately address the underlying causes of the
outages. FirstEnergy remains convinced that the outages cannot be explained
by
events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and
were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. FirstEnergy’s implementation of these
recommendations in 2004 included completion of the Task Force recommendations
that were directed toward FirstEnergy. FirstEnergy also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability that were to be completed subsequent to 2004 and will continue
to
periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new or material upgrades to existing
equipment, and therefore FirstEnergy has not accrued a liability as of
March 31, 2006 for any expenditure in excess of those actually incurred
through that date. The FERC or other applicable government agencies and
reliability coordinators may, however, take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room operators
before determining the next steps, if any, in the proceeding.
FirstEnergy
companies
also are defending six separate complaint cases before the PUCO relating to
the
August 14, 2003 power outage. Two cases were originally filed in Ohio State
courts but were subsequently dismissed for lack of subject matter jurisdiction
and further appeals were unsuccessful. In these cases the individual
complainants—three in one case and four in the other—sought to represent others
as part of a class action. The PUCO dismissed the class allegations, stating
that its rules of practice do not provide for class action complaints. Of the
four other pending PUCO complaint cases, three were filed by various insurance
carriers either in their own name as subrogees or in the name of their insured.
In each of these four cases, the carrier seeks reimbursement from various
FirstEnergy companies (and, in one case, from PJM, MISO and American Electric
Power Company, Inc. as well) for claims paid to insureds for damages allegedly
arising as a result of the loss of power on August 14, 2003. The listed
insureds in these cases, in many instances, are not customers of any FirstEnergy
company. The fourth case involves the claim of a non-customer seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of the
Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled
that
the U.S.-Canada Power System Outage Task Force Report was not admissible into
evidence; and gave the plaintiffs additional time to amend their complaints
to
otherwise comply with the PUCO’s underlying order.
The plaintiffs in
one case have since filed an amended complaint. The named FirstEnergy companies
have answered and also have filed a motion to dismiss the action, which is
pending. Also, most complainants, along with the FirstEnergy companies, filed
applications for rehearing with the PUCO over various rulings contained in
the
March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
the
insurance company claimants, as insurers, to prosecute their claims in their
name so long as they also identify the underlying insured entities and the
Ohio
utilities which provide their service. The PUCO denied all other motions for
rehearing. No estimate of potential liability is available for any of these
cases. In addition to these six cases, the Ohio Companies were named as
respondents in a regulatory proceeding that was initiated at the PUCO in
response to complaints alleging failure to provide reasonable and adequate
service stemming primarily from the August 14, 2003 power outages.
Following the PUCO's March 7, 2006 order, that action was voluntarily
dismissed by the claimants.
In
addition to the
above proceedings, FirstEnergy was named in a complaint filed in Michigan State
Court by an individual who is not a customer of any FirstEnergy company. A
responsive pleading to this matter has been filed. FirstEnergy was also named,
along with several other entities, in a complaint in New Jersey State Court.
The
allegations against FirstEnergy are based, in part, on an alleged failure to
protect the citizens of Jersey City from an electrical power outage. No
FirstEnergy entity serves any customers in Jersey City. A responsive pleading
has been filed. On April 28, 2006, the Court granted FirstEnergy's motion
to dismiss. It is uncertain whether the plaintiff will appeal. No estimate
of
potential liability has been undertaken in either of these matters.
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 the Companies. Although unable to predict the impact
of
these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
to have legal liability in connection with these proceedings, it could have
a
material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
Nuclear
Plant
Matters
On
January 20,
2006, FENOC announced that it has entered into a deferred prosecution agreement
with the U.S. Attorney’s Office for the Northern District of Ohio and the
Environmental Crimes Section of the Environment and Natural Resources Division
of the DOJ related to FENOC’s communications with the NRC during the fall of
2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power
Station. Under the agreement, which expires on December 31, 2006, the
United States acknowledged FENOC’s extensive corrective actions at Davis-Besse,
FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge
of continued cooperation in any related criminal and administrative
investigations and proceedings, FENOC’s acknowledgement of responsibility for
the behavior of its employees, and its agreement to pay a monetary penalty.
The
DOJ will refrain from seeking an indictment or otherwise initiating criminal
prosecution of FENOC for all conduct related to the statement of facts attached
to the deferred prosecution agreement, as long as FENOC remains in compliance
with the agreement, which FENOC fully intends to do. FENOC paid a monetary
penalty of $28 million (which is not deductible for income tax purposes)
which reduced First Energy's earnings by $0.09 per common share in the fourth
quarter of 2005.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty
related to the degradation of the Davis-Besse reactor vessel head issue
discussed above. FirstEnergy accrued $2 million for a potential fine prior
to 2005 and accrued the remaining liability for the proposed fine during the
first quarter of 2005. On September 14, 2005, FENOC filed its response to
the NOV with the NRC. FENOC accepted full responsibility for the past failure
to
properly implement its boric acid corrosion control and corrective action
programs. The NRC NOV indicated that the violations do not represent current
licensee performance. FirstEnergy paid the penalty in the third quarter of
2005.
On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
the Davis-Besse head degradation to reflect the deferred prosecution agreement
that FENOC had reached with the DOJ.
On
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take prompt
and corrective action. FENOC operates the Perry Nuclear Power Plant.
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the
NRC,
overall the Perry Nuclear Power Plant operated "in a manner that preserved
public health and safety" even though it remained under heightened NRC
oversight. During the public meeting and in the annual assessment, the NRC
indicated that additional inspections will continue and that the plant must
improve performance to be removed from the Multiple/Repetitive Degraded
Cornerstone Column of the Action Matrix. By an inspection report dated January
18, 2006, the NRC closed one of the White Findings (related to emergency
preparedness) which led to the multiple degraded cornerstones.
On
September 28,
2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made
to
improve the performance at the Perry Plant and stated that the CAL would remain
open until substantial improvement was demonstrated. The CAL was anticipated
as
part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment
letter dated March 2, 2006 and associated meetings to discuss the performance
of
Perry on March 14, 2006, the NRC again stated that the Perry Plant
continued to operate in a manner that "preserved public health and safety."
However, the NRC also stated that increased levels of regulatory oversight
would
continue until sustained improvement in the performance of the facility was
realized. If performance does not improve, the NRC has a range of options under
the Reactor Oversight Process, from increased oversight to possible impact
to
the plant’s operating authority. Although FirstEnergy is unable to predict the
impact of the ultimate disposition of this matter, it could have a material
adverse effect on FirstEnergy's or its subsidiaries' financial condition,
results of operations and cash flows.
Other
Legal
Matters
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy's normal business operations pending against FirstEnergy
and its subsidiaries. The other potentially material items not otherwise
discussed above are described below.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have
become the subject of a formal order of investigation. The SEC's formal order
of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
FirstEnergy received a subpoena asking for background documents and documents
related to the restatements and Davis-Besse issues. On December 30, 2004,
FirstEnergy received a subpoena asking for documents relating to issues raised
during the SEC's PUHCA examination. On August 24, 2005 additional
information was requested regarding Davis-Besse-related disclosures, which
has
been provided. FirstEnergy has cooperated fully with the informal inquiry and
continues to do so with the formal investigation.
On
August 22,
2005, a class action complaint was filed against OE in Jefferson County, Ohio
Common Pleas Court, seeking compensatory and punitive damages to be determined
at trial based on claims of negligence and eight other tort counts alleging
damages from W.H. Sammis Plant air emissions. The two named plaintiffs are
also
seeking injunctive relief to eliminate harmful emissions and repair property
damage and the institution of a medical monitoring program for class members.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16 million to the bargaining unit employees. On February 6, 2006, the
federal court granted a Union motion to dismiss JCP&L's appeal of the award
as premature. JCP&L will file its appeal again in federal district court
once the damages associated with this case are identified at an individual
employee level. JCP&L recognized a liability for the potential
$16 million award in 2005.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of a
newly-formed municipal electric utility. The complaint was filed on May 28,
2003, and OE timely filed its response on June 30, 2003. In a related
filing, the Ohio Companies filed for approval with the PUCO of a tariff that
would specifically allow the collection of transition charges from customers
of
municipal electric utilities formed after 1998. An adverse ruling could
negatively affect full recovery of transition charges by the utility. Hearings
on the matter were held in August 2005. Initial briefs from all parties were
filed on September 22, 2005 and reply briefs were filed on October 14,
2005. It is unknown when the PUCO will decide this case.
If
it were ultimately
determined that FirstEnergy or its subsidiaries have legal liability or are
otherwise made subject to liability based on the above matters, it could have
a
material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
11.
-
REGULATORY MATTERS:
RELIABILITY
INITIATIVES
In
late 2003 and
early 2004, a series of letters, reports and recommendations were issued from
various entities, including governmental, industry and ad hoc reliability
entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force)
regarding enhancements to regional reliability. In 2004, FirstEnergy completed
implementation of all actions and initiatives related to enhancing area
reliability, improving voltage and reactive management, operator readiness
and
training and emergency response preparedness recommended for completion in
2004.
On July 14, 2004, NERC independently verified that FirstEnergy had
implemented the various initiatives to be completed by June 30 or summer
2004, with minor exceptions noted by FirstEnergy, which exceptions are now
essentially complete. FirstEnergy is proceeding with the implementation of
the
recommendations that were to be completed subsequent to 2004 and will continue
to periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions
which may
impact the recommendations. Thus far, implementation of the recommendations
has
not required, nor is expected to require, substantial investment in new, or
material upgrades to existing equipment. The FERC or other applicable government
agencies and reliability coordinators may, however, take a different view as
to
recommended enhancements or may recommend additional enhancements in the future
as the result of adoption of mandatory reliability standards pursuant to the
EPACT that could require additional, material expenditures. Finally, the PUCO
is
continuing to review the FirstEnergy filing that addressed upgrades to control
room computer hardware and software and enhancements to the training of control
room operators before determining the next steps, if any, in the proceeding.
As
a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU
adopted a MOU that set out specific tasks related to service reliability to
be
performed by JCP&L and a timetable for completion and endorsed JCP&L’s
ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a
Stipulation that incorporates the final report of a Special Reliability Master
who made recommendations on appropriate courses of action necessary to ensure
system-wide reliability. The Stipulation also incorporates the Executive Summary
and Recommendation portions of the final report of a focused audit of
JCP&L’s Planning and Operations and Maintenance programs and practices
(Focused Audit). A final order in the Focused Audit docket was issued by the
NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the
DRA to discuss reliability improvements. JCP&L continues to file compliance
reports reflecting activities associated with the MOU and Stipulation.
In
May 2004, the
PPUC issued an order approving revised reliability benchmarks and standards,
including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed,
Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC
on
May 26, 2004, due to their implementation of automated outage management
systems following restructuring. On December 30, 2005, the ALJ recommended
that
the PPUC adopt the Joint Petition for Settlement among the parties involved
in
the three Companies’ request to amend the distribution reliability benchmarks,
thereby eliminating the need for full litigation. The ALJ’s recommendation,
adopting the revised benchmarks and standards, was approved by the PPUC on
February 9, 2006.
The
EPACT provides
for the creation of an ERO to establish and enforce reliability standards for
the bulk power system, subject to FERC review. On February 3, 2006, the FERC
adopted a rule establishing certification requirements for the ERO, as well
as
regional entities envisioned to assume monitoring responsibility for the new
reliability standards. The FERC issued an order on rehearing on March 30, 2006,
providing certain clarifications and essentially affirming the
rule.
The
NERC has been
preparing the implementation aspects of reorganizing its structure to meet
the
FERC’s certification requirements for the ERO. The NERC made a filing with the
FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
approval of delegation agreements with regional entities. The new FERC rule
referred to above, further provides for reorganizing regional reliability
organizations (regional entities) that would replace the current regional
councils and for rearranging the relationship with the ERO. The “regional
entity” may be delegated authority by the ERO, subject to FERC approval, for
enforcing reliability standards adopted by the ERO and approved by the FERC.
NERC also made a parallel filing with the FERC April 4, 2006 seeking approval
of
mandatory reliability standards. These
reliability
standards are based with some modifications, on the current NERC Version O
reliability standards with some additional standards. On May 2, 2006, the NERC
Board of Trustees adopted eight new cyber security standards and thirteen
additional reliability standards. These standards will become effective on
June
1, 2006 and will be filed with the FERC and relevant Canadian authorities for
approval. The
two filings are
subject to review and acceptance by the FERC.
The
ERO filing was
noticed on April 7, 2006 and comments and interventions were filed on
May 4, 2006. There is no fixed time for the FERC to act on this filing. The
reliability standards filing was noticed by FERC on April 18, 2006. In that
notice FERC announced its intent to treat the proposed reliability standards
as
a Notice of Proposed Rulemaking (NOPR), and issue a NOPR in July 2006. Prior
to
that time, the FERC staff will release a preliminary assessment of the proposed
reliability standards. FERC also intends to hold a technical conference on
the
proposed reliability standards. A comment period will be set after the Staff
assessment is released and the technical conference is held. NERC has requested
an effective date of January 1, 2007 for the reliability standards.
The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network
reliability councils have completed the consolidation of these regions into
a
single new regional reliability organization known as ReliabilityFirst
Corporation. ReliabilityFirst began operations as a regional reliability council
under NERC on January 1, 2006 and intends to file and obtain certification
consistent with the final rule as a “regional entity” under the ERO during 2006.
All of FirstEnergy’s facilities are located within the ReliabilityFirst
region.
FirstEnergy believes it is in compliance with all current NERC reliability
standards. However, it is expected that the FERC will adopt stricter reliability
standards than those contained in the current NERC standards. The financial
impact of complying with the new standards cannot be determined at this time.
However, the EPACT required that all prudent costs incurred to comply with
the
new reliability standards be recovered in rates.
OHIO
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On
August 5, 2004, the Ohio Companies accepted the RSP as modified and approved
by
the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP
was
intended to establish generation service rates beginning January 1, 2006,
in response to PUCO concerns about price and supply uncertainty following the
end of the Ohio Companies' transition plan market development period. In October
2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn
the original June 9, 2004 PUCO order in this proceeding as well as the
associated entries on rehearing. On September 28, 2005, the Ohio Supreme
Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court
of
Ohio issued an opinion affirming that order with respect to the approval of
the
rate stabilization charge, approval of the shopping credits, the grant of
interest on shopping credit incentive deferral amounts, and approval of
FirstEnergy’s financial separation plan. It remanded the approval of the RSP
pricing back to the PUCO for further consideration of the issue as to whether
the RSP, as adopted by the PUCO, provided for sufficient customer participation
in the competitive marketplace.
Under provisions of the RSP, the PUCO had required the Ohio Companies to
undertake a CBP to secure generation and allow for customer pricing
participation in the competitive marketplace. Any acceptance of future
competitive bid results would terminate the RSP pricing, with no accounting
impacts to the RSP, and not until 12 months after the PUCO authorizes such
termination. On December 9, 2004, the PUCO rejected the auction price
results from the CBP for the generation supply period beginning January 1,
2006
and issued an entry stating that the pricing under the approved revised RSP
would take effect on January 1, 2006. On February 23, 2006 the CBP
auction manager, National Economic Research Associates, notified the PUCO that
a
subsequent CBP to potentially provide firm generation service for the Ohio
Companies' 2007 and 2008 actual load requirements could not proceed due to
lack
of interest, as there were no bidder applications submitted. Additionally,
on
March 20, 2006, the PUCO denied applications for rehearing filed by various
parties regarding the PUCO's rules for the CBP. The above May 3, 2006
Supreme Court of Ohio opinion may require the PUCO to reconsider this customer
pricing process.
On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies'
RCP to supplement the RSP to provide customers with more certain rate levels
than otherwise available under the RSP during the plan period. Major provisions
of the RCP include:
|
·
|
Maintaining
the existing level of base distribution rates through December 31,
2008 for OE and TE, and April 30, 2009 for
CEI;
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·
|
Deferring
and
capitalizing for future recovery (over a 25-year period) with carrying
charges certain distribution costs to be incurred during the period
January 1, 2006 through December 31, 2008, not to exceed
$150 million in each of the three
years;
|
|
·
|
Adjusting
the
RTC and extended RTC recovery periods and rate levels so that full
recovery of authorized costs will occur as of December 31, 2008 for
OE and TE and as of December 31, 2010 for
CEI;
|
|
·
|
Reducing
the
deferred shopping incentive balances as of January 1, 2006 by up to
$75 million for OE, $45 million for TE, and $85 million for CEI
by accelerating the application of each respective company's accumulated
cost of removal regulatory liability;
and
|
|
·
|
Recovering
increased fuel costs (compared to a 2002 baseline) of up to $75 million,
$77 million, and $79 million, in 2006, 2007, and 2008,
respectively, from all OE and TE distribution and transmission customers
through a fuel recovery mechanism. OE, TE, and CEI may defer and
capitalize (for recovery over a 25-year period) increased fuel costs
above
the amount collected through the fuel recovery mechanism (in lieu
of
implementation of the GCAF rider).
|
The
PUCO’s January
4, 2006 approval of the RCP also included approval of the Ohio
Companies’
supplemental
stipulation which was filed with the PUCO on November 4, 2005 and which was
an
additional component of the RCP filed on September 9, 2005. On
January 10, 2006, the Ohio Companies filed a Motion for Clarification of
the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
related to distribution deferrals, including requirements of the review process,
timing for recognizing certain deferrals and definitions of the types of
qualified expenditures. The Ohio Companies also sought confirmation that the
list of deferrable distribution expenditures originally included in the revised
stipulation fall within the PUCO order definition of qualified expenditures.
On
January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
and denying in part, the Ohio Companies’ previous requests and clarifying issues
referred to above. The PUCO granted the Ohio Companies’ requests to:
|
·
|
Recognize
fuel
and distribution deferrals commencing January 1,
2006;
|
|
|
|
|
·
|
Recognize
distribution deferrals on a monthly basis prior to review by the
PUCO
Staff;
|
|
|
|
|
·
|
Clarify
that
the types of distribution expenditures included in the Supplemental
Stipulation may be deferred; and
|
|
|
|
|
·
|
Clarify
that
distribution expenditures do not have to be “accelerated” in order to be
deferred.
|
The
PUCO approved the
Ohio Companies’ methodology for determining distribution deferral amounts, but
denied the Motion in that the PUCO Staff must verify the level of distribution
expenditures contained in current rates, as opposed to simply accepting the
amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several
other parties filed applications for rehearing on the PUCO's January 4,
2006 Order. The Ohio Companies responded to the applications for rehearing
on
February 13, 2006. In an Entry on Rehearing issued by the PUCO on
March 1, 2006, all motions for rehearing were denied. Certain of these
parties have subsequently filed their notices of appeal with the Supreme Court
of Ohio alleging various errors made by the PUCO in its order approving the
RCP.
On
December 30,
2004, the Ohio Companies filed with the PUCO two applications related to the
recovery of transmission and ancillary service related costs. The first
application sought recovery of these costs beginning January 1, 2006. The
Ohio Companies requested that these costs be recovered through a rider that
would be effective on January 1, 2006 and adjusted each July 1
thereafter. The parties reached a settlement agreement that was approved by
the
PUCO on August 31, 2005. The incremental transmission and ancillary service
revenues expected to be recovered from January through June 30, 2006 are
approximately $66 million. This amount includes the recovery of the 2005
deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies
filed a modification to the rider to determine revenues from July 2006 through
June 2007.
The
second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO granted the
accounting authority for the Ohio Companies to defer incremental transmission
and ancillary service-related charges incurred as a participant in MISO, but
only for those costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
to accrue carrying charges on the deferred balances. On August 31, 2005,
the OCC appealed the PUCO's decision. All briefs have been filed. On March
20,
2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal
of the Ohio Companies' case with a similar case involving Dayton Power &
Light Company. Oral arguments are currently scheduled for May 10,
2006.
On
January 20,
2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred
costs through the rider during the period January 1, 2006 through June 30,
2006. The PUCO denied the OCC's application on February 6, 2006. On March
23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
OCC's
brief is expected to be filed during the second quarter of 2006. The briefs
of
the PUCO and the Ohio Companies will be due within thirty days of the OCC's
filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal
with the deferral appeals discussed above and to postpone oral arguments in
the
deferral appeal until after all briefs are filed in this most recent appeal
of
the rider recovery mechanism. On April 18, 2006, the Court denied both parts
of
the motion but on its own motion consolidated the OCC's appeal of the Ohio
Companies' case with a similar case of Dayton Power & Light Company and
stayed briefing on these appeals.
PENNSYLVANIA
A
February 2002
Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision
regarding approval of the FirstEnergy/GPU merger, remanded the issues of
quantification and allocation of merger savings to the PPUC and denied Met-Ed
and Penelec the rate relief initially approved in the PPUC decision. On
October 2, 2003, the PPUC issued an order concluding that the Commonwealth
Court reversed the PPUC’s June 2001 order in its entirety. In accordance
with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs
that became effective in October 2003 and that reflected the CTC rates and
shopping credits in effect prior to the June 2001 order.
Met-Ed’s
and
Penelec’s combined portion of total net merger savings during 2001 - 2004 is
estimated to be approximately $51 million. A procedural schedule was established
by the ALJ on January 17, 2006. The companies’ filed initial testimony on
March 1, 2006. Hearings are currently scheduled for the end of October 2006
with
the ALJ’s recommended decision to be issued in February 2007. The companies have
requested that this proceeding be consolidated with the April 10, 2006
transition plan filing proceeding as discussed below. Met-Ed and Penelec are
unable to predict the outcome of this proceeding.
In
an
October 16, 2003 order, the PPUC approved September 30, 2004 as the
date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
denied their accounting treatment request regarding the CTC rate/shopping credit
swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
were
in effect from January 1, 2002 on a retroactive basis. On October 22,
2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
that the Court reverse this PPUC finding; a Commonwealth Court judge
subsequently denied their Objection on October 27, 2003 without
explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
for Clarification of the Court order with the Commonwealth Court, a Petition
for
Review of the PPUC's October 2 and October 16, 2003 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.
The Reargument Brief before the Commonwealth Court was filed on January 28,
2005. Oral arguments are scheduled for June 8, 2006.
As
of March 31,
2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998
Restructuring Settlement (including the Phase 2 Proceedings) and the
FirstEnergy/GPU Merger Settlement Stipulation are $328 million and
$50 million, respectively. Penelec's $50 million is subject to the pending
resolution of taxable income issues associated with NUG trust fund proceeds.
On
January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for
deferral of transmission-related costs beginning January 1, 2005. The OCA,
OSBA,
OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
Association have all intervened in the case. As of March 31, 2006, the PPUC
had
taken no action on the request and neither company had yet implemented deferral
accounting for these costs. Met-Ed and Penelec sought to consolidate this
proceeding (and modified their request to provide deferral of 2006
transmission-related costs only) with the comprehensive rate filing they made
on
April 10, 2006 as described below. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Met-Ed and Penelec will implement deferral
accounting for these costs in the second quarter of 2006, which will include
$24
million and $4 million, respectively, representing the amounts that were
incurred in the first quarter of 2006 - the deferrals of such amounts will
be
reflected in the second quarter of 2006.
Met-Ed
and Penelec
purchase a portion of their PLR requirements from FES through a wholesale power
sales agreement. Under this 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 contracts with NUGs and other
unaffiliated suppliers. The FES 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.
The wholesale power sales agreement with FES could automatically be extended
for
each successive calendar year unless any party elects to cancel the agreement
by
November 1 of the preceding year. On November 1, 2005, FES and the other
parties thereto amended the agreement to provide FES the right in 2006 to
terminate the agreement at any time upon 60 days notice. On April 7, 2006,
the parties to the wholesale power sales agreement entered into a Tolling
Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
to exercise its right to terminate the wholesale power sales agreement effective
midnight December 31, 2006, because that agreement is not economically
sustainable to FES.
In
lieu of allowing
such termination to become effective as of December 31, 2006, the parties
agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales
agreement to provide as follows:
1. The
termination
provisions of the wholesale power sales agreement will be tolled for one year
until December 31, 2007, provided that during such tolling period:
a. FES
will be
permitted to terminate the wholesale power sales agreement at any time with
sixty days written notice;
b. Met-Ed
and Penelec
will procure through arrangements other than the wholesale power sales agreement
beginning December 1, 2006 and ending December 31, 2007, approximately 33%
of
the amounts of capacity and energy necessary to satisfy their PLR obligations
for which Committed Resources (i.e., non-utility generation under contract
to
Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased
power contracts and distributed generation) have not been obtained;
and
c. FES
will not be
obligated to supply additional quantities of capacity and energy in the event
that a supplier of Committed Resources defaults on its supply
agreement.
2. During
the tolling
period FES will not act as agent for Met-Ed or Penelec in procuring the services
under section 1.(b) above; and
3. The
pricing
provision of the wholesale power sales agreement shall remain unchanged provided
Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
any
applicable provision of the wholesale power sales agreement.
In
the event that
FES elects not to terminate the wholesale power sales agreement effective
midnight December 31, 2007, similar tolling agreements effective after
December 31, 2007 are expected to be considered by FES for subsequent years
if
Met-Ed and Penelec procure through arrangements other than the wholesale power
sales agreement approximately 64%, 83% and 95% of the additional amounts of
capacity and energy necessary to satisfy their PLR obligations for 2008, 2009
and 2010, respectively, for which Committed Resources have not been obtained
from the market.
The
wholesale power
sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
Penelec to satisfy the portion of their PLR obligations currently supplied
by
FES from unaffiliated suppliers at prevailing prices, which are likely to be
higher than the current price charged by FES under the current agreement and,
as
a result, Met-Ed’s and Penelec’s purchased power costs could materially
increase. If Met-Ed and Penelec were to replace the entire FES supply at current
market power prices without corresponding regulatory authorization to increase
their generation prices to customers, each company would likely incur a
significant increase in operating expenses and experience a material
deterioration in credit quality metrics. Under such a scenario, each company's
credit profile would no longer be expected to support an investment grade rating
for its fixed income securities. There can be no assurance, however, that if
FES
ultimately determines to terminate, or significantly modify the agreement,
timely regulatory relief will be granted by the PPUC pursuant to the April
10,
2006 comprehensive rate filing discussed below, or, to the extent granted,
adequate to mitigate such adverse consequences.
Met-Ed
and Penelec
made a comprehensive rate filing with the PPUC on April 10, 2006 that
addresses a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals is approved,
the
filing would increase annual revenues by $216 million and $157 million,
respectively. That filing includes, among other things, a request to charge
customers for an increasing amount of market priced power procured through
a
competitive bid process as the amount of supply provided under the existing
FES
agreement is phased out in accordance with the April 7, 2006 Tolling agreement
described above. Met-Ed
and Penelec
also requested approval of the January 12, 2005 petition for the deferral of
transmission-related costs discussed above, but only for those costs incurred
during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
of
annual transmission and related costs incurred on or after January 1, 2007,
plus the amortized portion of 2006 costs over a ten-year period, along with
applicable carrying charges, through an adjustable rider similar to that
implemented in Ohio.
Changes in the
recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
are
also included in the filing. The filing contemplates a reduction in distribution
rates for Met-Ed in the amount of $37 million annually and an increase in
distribution rates for Penelec in the amount of $20 million annually. Although
the companies have proposed an effective date of June 10, 2006, it is
expected that the PPUC will suspend the effective date for seven months as
permitted under Pennsylvania law. Hearings are expected to be scheduled for
the
second half of 2006 and a PPUC decision is expected early in the first quarter
of 2007.
On
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for its
customers at set rates following the end of its transition period on
December 31, 2006. Penn recommended that the RFP process cover the period
January 1, 2007 through May 31, 2008. Hearings were held on
January 10, 2006 with main briefs filed on January 27, 2006 and reply
briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a
Recommended Decision to adopt Penn's RFP process with modifications. The PPUC
approved the Recommended Decision with additional modifications on
April 20, 2006. The approved plan is designed to provide customers with PLR
service for January 1, 2007 through May 31, 2008. Under Pennsylvania's
electric competition law, Penn is required to secure generation supply for
customers who do not choose alternative suppliers for their electricity.
NEW
JERSEY
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 NUGC rates and market sales
of NUG energy and capacity. As of March 31, 2006, the accumulated deferred
cost
balance totaled approximately $558 million. New Jersey law allows for
securitization of JCP&L's deferred balance upon application by JCP&L and
a determination by the NJBPU that the conditions of the New Jersey restructuring
legislation are met. On February 14, 2003, JCP&L filed for approval to
securitize the July 31, 2003 deferred balance. On December 2, 2005,
JCP&L filed a request for recovery of $165 million of actual
above-market NUG costs incurred from August 1, 2003 through
October 31, 2005 and forecasted above-market NUG costs for November and
December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the
financial advisor. Meetings with the NJBPU Staff and the DRA were held during
March and April and additional discovery conducted. The DRA filed comments
on
April 6, 2006, arguing that the proposed securitization does not produce
customer savings. JCP&L submitted reply comments on April 10, 2006. On
February 23, 2006, JCP&L filed updated data reflecting actual amounts
through December 31, 2005 of $154 million of cost incurred since
July 31, 2003. The filing also includes a request for recovery of
$49 million for above-market NUG costs incurred prior to August 1,
2003, to the extent those costs are not recoverable through securitization.
On
March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A
schedule for the proceeding was established, including a discovery period and
evidentiary hearings scheduled for September 2006.
An
NJBPU Decision
and Order approving a Phase II Stipulation of Settlement and resolving the
Motion for Reconsideration of the Phase I Order was issued on May 31, 2005.
The
Phase II Settlement includes a performance standard pilot program with potential
penalties of up to 0.25% of allowable equity return. The Order requires that
JCP&L file quarterly reliability reports (CAIDI and SAIFI information
related to the performance pilot program) through December 2006 and updates
to
reliability related project expenditures until all projects are completed.
The
first quarterly report was submitted to NJBPU on August 16, 2005. The second
quarterly report was submitted on November 22, 2005. The third quarterly
report as of December 31, 2005 was submitted on March 28, 2006. As of
December 31, 2005 there were no performance penalties issued by the
NJBPU.
JCP&L
sells all
self-supplied energy (NUGs and owned generation) to the wholesale market with
offsetting credits to its deferred energy balance with the exception of 300
MW
from JCP&L's NUG committed supply currently being used to serve BGS
customers pursuant to an NJBPU order for the period June 1, 2005 through
May 31, 2006.
The
NJBPU decision
approving the BGS procurement proposal for the period beginning June 1,
2006 was issued on October 12, 2005. JCP&L submitted a compliance
filing on October 26, 2005, which was approved on November 10, 2005.
The written order was dated December 8, 2005. The auction took place in
February 2006. On February 9, 2006, the NJBPU approved the auction results
and a written order was signed on February 23, 2006. The JCP&L tariff
compliance filing was approved on March 29, 2006. New BGS rates become effective
June 1, 2006.
In
a reaction to the
higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on
March 16, 2006, initiated a generic proceeding to evaluate the auction
process and potential options for the future. On April 6, 2006, initial
comments were submitted. A public meeting was held on April 21, 2006 and a
legislative-type hearing was held on April 28, 2006. Final comments were
due on May 4, 2006. An NJBPU decision is anticipated in June 2006.
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 customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The DRA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. A schedule for further proceedings
has not yet been set.
On
August 1, 2005, the NJBPU established a proceeding to determine whether
additional ratepayer protections are required at the state level in light of
the
recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address
the issues was published in the NJ Register on December 19, 2005. The
proposal would prevent a holding company that owns a gas or electric public
utility from investing more than 25% of the combined assets of its utility
and
utility-related subsidiaries into businesses unrelated to the utility industry.
A public hearing was held February 7, 2006 and comments were submitted to
the NJBPU. The
NJBPU Staff
issued a draft proposal on March 31, 2006 addressing various issues
including access to books and records, ring-fencing, cross subsidization,
corporate governance and related matters. Comments and reply comments are due
by
May 22 and May 31, 2006, respectively. JCP&L is not able to predict the
outcome of this proceeding at this time.
On
December 21,
2005, the NJBPU initiated a generic proceeding and requested comments in order
to formulate an appropriate regulatory treatment for investment tax credits
related to generation assets divested by New Jersey’s four electric utility
companies. Comments were filed by the utilities and by the DRA.
FERC
MATTERS
On
November 1, 2004, ATSI filed with FERC a request to defer approximately
$54 million of costs to be incurred from 2004 through 2007 in connection
with ATSI’s Vegetation Management Enhancement Project (VMEP), which represents
ATSI’s adoption of newly identified industry “best practices” for vegetation
management. On March 4, 2005, the FERC approved ATSI’s request to defer the
VMEP costs (approximately $29 million deferred as of March 31, 2006). On
March 28, 2006 ATSI and MISO filed with FERC a request to modify ATSI’s
Attachment O formula rate to include revenue requirements associated with
recovery of deferred VMEP costs over a five-year period. The requested effective
date to begin recovery is June 1, 2006. Various parties have filed comments
responsive to the March 28, 2006 submission. The FERC has not taken any
action on the filing. The estimated impact of the VMEP cost recovery is
$13 million in revenues annually during the five-year recovery period of
June 1, 2006 to May 31, 2011.
On
January 24, 2006,
ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O formula
rate to reverse revenue credits associated with termination of revenue streams
from transitional rates stemming from FERC’s elimination of through and out
rates. Revenues formerly collected under these rates were included in, and
served to reduce, ATSI’s zonal transmission rate under the Attachment O formula.
Absent the requested correction, elimination of these revenue streams would
not
be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16,
2006, FERC approved without suspension the revenue credit correction, which
became effective April 1, 2006. One party sought rehearing of the FERC's order.
The FERC has not yet issued a further order. The estimated impact of the
correction mechanism is approximately $40 million in revenues on an annualized
basis beginning June 1, 2006.
On
November 18,
2004, the FERC issued an order eliminating the regional through and out rates
(RTOR) for transmission service between the MISO and PJM regions. The FERC
also
ordered the MISO, PJM and the transmission owners within the MISO and PJM to
submit compliance filings containing a mechanism - the Seams Elimination Cost
Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
period from load serving entities. The FERC issued orders in 2005 setting the
SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
involved in the FERC hearings concerning the calculation and imposition of
the
SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
Presiding Judge to issue an initial decision by August 11,
2006.
On
January 31,
2005, certain PJM transmission owners made three filings with the FERC pursuant
to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In
the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. In the second
filing, the settling transmission owners proposed a revised Schedule 12 to
the PJM tariff designed to harmonize the rate treatment of new and existing
transmission facilities. Interventions and protests were filed on
February 22, 2005. In the third filing, Baltimore Gas and Electric Company
and Pepco Holdings, Inc. requested a formula rate for transmission service
provided within their respective zones. On May 31, 2005, the FERC issued an
order on these cases. First, it set for hearing the existing rate design and
indicated that it will issue a final order within six months. American
Electric
Power Company, Inc. filed in opposition proposing to create a "postage stamp"
rate for high voltage transmission facilities across PJM.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to referral and hearing procedures. On
June 30, 2005, the settling PJM transmission owners filed a request for
rehearing of
the May 31,
2005
order. On
March 20, 2006 a settlement was filed with FERC in the formula rate
proceeding that generally accepts the companies' formula rate proposal. The
FERC
issued an order approving this settlement on April 19, 2006. If the FERC accepts
AEP's proposal, significant additional transmission revenues would be imposed
on
JCP&L, Met-Ed, Penelec, and other transmission zones within
PJM.
On
November 1, 2005,
FES filed two power sales agreements for approval with the FERC. One power
sales
agreement provided for FES to provide the PLR requirements of the Ohio Companies
at a price equal to the retail generation rates approved by the PUCO for a
period of three years beginning January 1, 2006. The Ohio Companies will be
relieved of their obligation to obtain PLR power requirements from FES if the
Ohio competitive bid process results in a lower price for retail customers.
A
similar power sales agreement between FES and Penn permits Penn to obtain its
PLR power requirements from FES at a fixed price equal to the retail generation
price during 2006. The PPUC approved Penn's plan with modifications on April
20,
2006 to use an RFP process to obtain its power supply requirements after
2006.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio competitive bid process, and required
FES
to submit additional evidence in support of the reasonableness of the prices
charged in the power sales agreements. A pre-hearing conference was held on
January 18, 2006 to determine the hearing schedule in this case. FES
expects an initial decision to be issued in this case in late January 2007,
as a
result of an April 20, 2006 extension of the procedural schedule. The outcome
of
this proceeding cannot be predicted. FES has sought rehearing of the
December 29, 2005 order and the FERC granted rehearing for further
consideration on March 1, 2006.
12.
- NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or more
legally separate exchange transactions with the same counterparty should be
combined and considered as a single arrangement for purposes of applying APB
29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the EITF
reached a consensus that an exchange of inventory should be accounted for at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, FirstEnergy will adopt this EITF
effective for new arrangements entered into, or modifications or renewals of
existing arrangements, in interim or annual periods beginning after
March 15, 2006. This EITF Issue will not have a material impact on
FirstEnergy's financial results.
|
SFAS
155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment
of FASB
Statements No. 133 and 140”
|
In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities.” This Statement permits fair value remeasurement for any hybrid
financial instrument that contains an embedded derivative that otherwise would
require bifurcation, clarifies which interest-only strips and principal-only
strips are not subject to the requirements of SFAS 133, establishes a
requirement to evaluate interests in securitized financial assets to identify
interests that are freestanding derivatives or that are hybrid financial
instruments that contain an embedded derivative requiring bifurcation, clarifies
that concentrations of credit risk in the form of subordination are not embedded
derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
special-purpose entity from holding a derivative financial instrument that
pertains to a beneficial interest other than another derivative instrument.
This
Statement is effective for all financial instruments acquired or issued
beginning January 1, 2007. FirstEnergy is currently evaluating the impact
of this Statement on its financial statements.
13.
-
SEGMENT INFORMATION:
FirstEnergy
has two
reportable segments: regulated services and power supply management services.
The aggregate “Other” segments do not individually meet the criteria to be
considered a reportable segment. The regulated services segment's operations
include the regulated sale of electricity and distribution and transmission
services by its eight utility subsidiaries in Ohio, Pennsylvania and New Jersey.
The power supply management services segment primarily consists of the
subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated
markets and operate and now own the generation facilities of OE, CEI, TE and
Penn resulting from the deregulation of the Companies' electric generation
business. “Other” consists of telecommunications services, the recently sold MYR
(a construction service company) and retail natural gas operations (see Note
4).
The assets and revenues for the other business operations are below the
quantifiable threshold for operating segments for separate disclosure as
“reportable segments.”
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. Assets of the
regulated services segment as of March 31, 2005 included generating units that
were leased or whose output had been sold to the power supply management
services segment. The regulated services segment’s 2005 internal revenues
represented the rental revenues for the generating unit leases which ceased
in
the fourth quarter of 2005 as a result of the intra-system generation asset
transfers (see Note 14).
The
power supply
management services segment supplies all of the electric power needs of
FirstEnergy’s end-use customers through retail and wholesale arrangements,
including regulated retail sales to meet the PLR requirements of FirstEnergy's
Ohio and Pennsylvania companies and competitive retail sales to commercial
and
industrial businesses primarily in Ohio, Pennsylvania and Michigan. This
business segment owns and operates FirstEnergy's generating facilities and
purchases electricity from the wholesale market when needed to meet sales
obligations. The segment's net income is primarily derived from all electric
generation sales revenues less the related costs of electricity generation,
including purchased power and net transmission, congestion and ancillary costs
charged by PJM and MISO to deliver energy to retail customers.
Segment
reporting
for interim periods in 2005 was reclassified to conform to the current year
business segment organization and operations and the reclassification of
discontinued operations (see Note 4). Changes in the current year operations
reporting reflected in reclassifications of 2005 segment reporting primarily
includes the transfer of the net results of retail transmission revenues and
PJM/MISO transmission revenues and expenses associated with serving electricity
load previously included in the regulated services segment to the power supply
management services segment. In addition, as a result of the 2005 Ohio tax
legislation reducing the effective state income tax rate, the calculated
composite income tax rate used in the two reportable segments results for 2005
and 2006 has been changed to 40% from the 41% previously reported in their
2005
segment results. The net amount of the changes in the 2005 reportable segments'
income taxes reclassifications has been correspondingly offset in the 2005
"Reconciling Adjustments." FSG is being disclosed as a reporting segment due
to
its subsidiaries qualifying as held for sale. Interest expense on holding
company debt and corporate support services revenues and expenses are included
in "Reconciling Adjustments."
Segment
Financial Information
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Facilities
|
|
|
|
Reconciling
|
|
|
|
Three
Months Ended
|
|
Services
|
|
Services
|
|
Services
|
|
Other
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
March
31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,083
|
|
$
|
1,619
|
|
$
|
46
|
|
$
|
120
|
|
$
|
(23
|
)
|
$
|
2,845
|
|
Internal
revenues
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
revenues
|
|
|
1,083
|
|
|
1,619
|
|
|
46
|
|
|
120
|
|
|
(23
|
)
|
|
2,845
|
|
Depreciation
and amortization
|
|
|
259
|
|
|
46
|
|
|
-
|
|
|
1
|
|
|
5
|
|
|
311
|
|
Investment
Income
|
|
|
62
|
|
|
15
|
|
|
-
|
|
|
-
|
|
|
(34
|
)
|
|
43
|
|
Net
interest
charges
|
|
|
93
|
|
|
49
|
|
|
-
|
|
|
1
|
|
|
17
|
|
|
160
|
|
Income
taxes
|
|
|
144
|
|
|
27
|
|
|
-
|
|
|
(7
|
)
|
|
(30
|
)
|
|
134
|
|
Net
income
|
|
|
211
|
|
|
40
|
|
|
(1
|
)
|
|
15
|
|
|
(44
|
)
|
|
221
|
|
Total
assets
|
|
|
23,848
|
|
|
6,759
|
|
|
63
|
|
|
304
|
|
|
823
|
|
|
31,797
|
|
Total
goodwill
|
|
|
5,916
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,940
|
|
Property
additions
|
|
|
195
|
|
|
244
|
|
|
-
|
|
|
1
|
|
|
7
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,216
|
|
$
|
1,377
|
|
$
|
43
|
|
$
|
112
|
|
$
|
2
|
|
$
|
2,750
|
|
Internal
revenues
|
|
|
78
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(78
|
)
|
|
-
|
|
Total
revenues
|
|
|
1,294
|
|
|
1,377
|
|
|
43
|
|
|
112
|
|
|
(76
|
)
|
|
2,750
|
|
Depreciation
and amortization
|
|
|
374
|
|
|
13
|
|
|
-
|
|
|
1
|
|
|
6
|
|
|
394
|
|
Investment
income
|
|
|
41
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
41
|
|
Net
interest
charges
|
|
|
98
|
|
|
10
|
|
|
-
|
|
|
1
|
|
|
62
|
|
|
171
|
|
Income
taxes
|
|
|
157
|
|
|
(30
|
)
|
|
(3
|
)
|
|
10
|
|
|
(13
|
)
|
|
121
|
|
Income
before
discontinued operations
|
|
|
236
|
|
|
(46
|
)
|
|
(2
|
)
|
|
5
|
|
|
(52
|
)
|
|
141
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
13
|
|
|
6
|
|
|
-
|
|
|
19
|
|
Net
income
|
|
|
236
|
|
|
(46
|
)
|
|
11
|
|
|
11
|
|
|
(52
|
)
|
|
160
|
|
Total
assets
|
|
|
28,540
|
|
|
1,582
|
|
|
83
|
|
|
495
|
|
|
561
|
|
|
31,261
|
|
Total
goodwill
|
|
|
5,947
|
|
|
24
|
|
|
-
|
|
|
63
|
|
|
-
|
|
|
6,034
|
|
Property
additions
|
|
|
141
|
|
|
81
|
|
|
1
|
|
|
2
|
|
|
4
|
|
|
229
|
|
Reconciling
adjustments to segment operating results from internal management reporting
to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses, fuel marketing revenues (which are reflected as reductions to expenses
for internal management reporting purposes) and elimination of intersegment
transactions.
14.
-
FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS
On
May 13,
2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
agreements implementing a series of intra-system generation asset transfers
that
were completed in the fourth quarter of 2005. The asset transfers resulted
in
the respective undivided ownership interests of the Ohio Companies and Penn
in
FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
FGCO, respectively. The generating plant interests transferred do not include
leasehold interests of CEI, TE and OE in certain of the plants that are
currently subject to sale and leaseback arrangements with non-affiliates.
On
October 24, 2005,
the Ohio Companies and Penn completed the intra-system transfer of non-nuclear
generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master
Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
the non-nuclear generation assets that it now owns. The asset transfers were
consummated pursuant to FGCO's purchase option under the Master Facility
Lease.
On
December 16,
2005, the Ohio Companies and Penn completed the intra-system transfer of their
respective ownership in the nuclear generation assets to NGC through, in the
case of OE and Penn, an asset spin-off by way of dividend and, in the case
of
CEI and TE, a sale at net book value. FENOC continues to operate and maintain
the nuclear generation assets.
These
transactions
were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were
approved by the PUCO and the PPUC, respectively, under applicable Ohio and
Pennsylvania electric utility restructuring legislation. Consistent with the
restructuring plans, generation assets that had been owned by the Ohio Companies
and Penn were required to be separated from the regulated delivery business
of
those companies through transfer to a separate corporate entity. The
transactions essentially completed the divestitures contemplated by the
restructuring plans by transferring the ownership interests to NGC and FGCO
without impacting the operation of the plants.
JCP&L's earnings for the three months ended March 31, 2005 have been
restated to reflect the results of a tax audit by the State of New Jersey,
in
which JCP&L became aware that the New Jersey Transitional Energy Facilities
Assessment (TEFA) is not an allowable deduction for state income tax purposes.
JCP&L had incorrectly claimed a state income tax deduction for TEFA payments
and as a result, income taxes and interest expense were understated by
$0.5 million and $0.6 million, respectively, in the first quarter of 2005.
The effects of these adjustments on JCP&L's Consolidated Statements of
Income for the three months ended March 31, 2005 are as follows:
|
|
As
Previously
|
|
As
|
|
|
Reported
|
|
Restated
|
|
|
(In
millions)
|
Operating
Revenues
|
|
$
|
529.1
|
|
$
|
529.1
|
Operating
Expenses and
|
|
|
|
|
|
|
Taxes
|
|
|
494.7
|
|
|
495.2
|
Operating
Income
|
|
|
34.4
|
|
|
33.9
|
Net
Interest
Charges
|
|
|
19.9
|
|
|
20.5
|
Net
Income
|
|
$
|
14.5
|
|
$
|
13.4
|
Earnings
Applicable
|
|
|
|
|
|
|
to
Common
Stock
|
|
$
|
14.4
|
|
$
|
13.3
|
These
adjustments
were not material to FirstEnergy's consolidated financial statements, nor
JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash
Flows.
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
March
31,
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
Electric
utilities
|
$ |
2,340
|
|
$
|
2,267
|
|
|
Unregulated
businesses
|
|
505
|
|
|
483
|
|
|
|
Total
revenues
|
|
2,845
|
|
|
2,750
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
976
|
|
|
895
|
|
|
Other
operating expenses
|
|
893
|
|
|
884
|
|
|
Provision
for
depreciation
|
|
148
|
|
|
143
|
|
|
Amortization
of regulatory assets
|
|
222
|
|
|
311
|
|
|
Deferral
of
new regulatory assets
|
|
(59
|
) |
|
(60
|
) |
|
General
taxes
|
|
193
|
|
|
185
|
|
|
|
Total
expenses
|
|
2,373
|
|
|
2,358
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
472
|
|
|
392
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
Investment
income
|
|
43
|
|
|
41
|
|
|
Interest
expense
|
|
(165
|
) |
|
(164
|
) |
|
Capitalized
interest
|
|
7
|
|
|
-
|
|
|
Subsidiaries’
preferred stock dividends
|
|
(2
|
) |
|
(7
|
) |
|
|
Total
other
income (expense)
|
|
(117
|
) |
|
(130
|
) |
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
134
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
221
|
|
|
141
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income tax benefit of $8 million)
|
|
|
|
|
|
|
|
(Note
4)
|
|
-
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
$ |
221
|
|
$
|
160
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
0.67
|
|
$
|
0.43
|
|
|
Discontinued
operations (Note 4)
|
|
-
|
|
|
0.06
|
|
|
Net
income
|
$ |
0.67
|
|
$
|
0.49
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
329
|
|
|
328
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
$ |
0.67
|
|
$
|
0.42
|
|
|
Discontinued
operations (Note 4)
|
|
-
|
|
|
0.06
|
|
|
Net
income
|
$ |
0.67
|
|
$
|
0.48
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
330
|
|
|
329
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
$ |
0.45
|
|
$
|
0.4125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
March
31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
$
|
221
|
|
$
|
160
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
43
|
|
|
7
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
36
|
|
|
(8
|
)
|
|
|
Other
comprehensive income (loss)
|
|
79
|
|
|
(1
|
)
|
|
Income
tax
expense related to other comprehensive income
|
|
32
|
|
|
-
|
|
|
|
Other
comprehensive income (loss), net of tax
|
|
47
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
$
|
268
|
|
$
|
159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
$
|
28
|
|
$
|
64
|
|
|
Receivables
-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $37 million and
|
|
|
|
|
|
|
|
|
|
$38
million,
respectively, for uncollectible accounts)
|
|
1,072
|
|
|
1,293
|
|
|
|
Other
(less
accumulated provisions of $27 million
|
|
|
|
|
|
|
|
|
|
for
uncollectible accounts in both periods)
|
|
154
|
|
|
205
|
|
|
Materials
and
supplies, at average cost
|
|
610
|
|
|
518
|
|
|
Prepayments
and other
|
|
235
|
|
|
237
|
|
|
|
|
|
|
|
2,099
|
|
|
2,317
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
In
service
|
|
23,071
|
|
|
22,893
|
|
|
Less
-
Accumulated provision for depreciation
|
|
9,859
|
|
|
9,792
|
|
|
|
|
|
|
|
13,212
|
|
|
13,101
|
|
|
Construction
work in progress
|
|
1,073
|
|
|
897
|
|
|
|
|
|
|
|
14,285
|
|
|
13,998
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
1,818
|
|
|
1,752
|
|
|
Investments
in
lease obligation bonds
|
|
845
|
|
|
890
|
|
|
Other
|
|
|
805
|
|
|
765
|
|
|
|
|
|
|
|
3,468
|
|
|
3,407
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
5,940
|
|
|
6,010
|
|
|
Regulatory
assets
|
|
4,396
|
|
|
4,486
|
|
|
Prepaid
pension costs
|
|
1,018
|
|
|
1,023
|
|
|
Other
|
|
|
591
|
|
|
600
|
|
|
|
|
|
|
|
11,945
|
|
|
12,119
|
|
|
|
|
|
|
$
|
31,797
|
|
$
|
31,841
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
$
|
2,115
|
|
$
|
2,043
|
|
|
Short-term
borrowings
|
|
931
|
|
|
731
|
|
|
Accounts
payable
|
|
612
|
|
|
727
|
|
|
Accrued
taxes
|
|
803
|
|
|
800
|
|
|
Other
|
|
|
989
|
|
|
1,152
|
|
|
|
|
|
|
|
5,450
|
|
|
5,453
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholders’ equity -
|
|
|
|
|
|
|
|
|
Common
stock,
$.10 par value, authorized 375,000,000 shares -
|
|
|
|
|
|
|
|
|
|
329,836,276
shares outstanding
|
|
33
|
|
|
33
|
|
|
|
Other
paid-in
capital
|
|
7,050
|
|
|
7,043
|
|
|
|
Accumulated
other comprehensive income (loss)
|
|
27
|
|
|
(20
|
)
|
|
|
Retained
earnings
|
|
2,232
|
|
|
2,159
|
|
|
|
Unallocated
employee stock ownership plan common stock -
|
|
|
|
|
|
|
|
|
|
1,167,865
and
1,444,796 shares, respectively
|
|
(22
|
)
|
|
(27
|
) |
|
|
|
|
Total
common
stockholders' equity
|
|
9,320
|
|
|
9,188
|
|
|
Preferred
stock of consolidated subsidiaries
|
|
154
|
|
|
184
|
|
|
Long-term
debt
and other long-term obligations
|
|
8,004
|
|
|
8,155
|
|
|
|
|
|
|
|
17,478
|
|
|
17,527
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
2,759
|
|
|
2,726
|
|
|
Asset
retirement obligations
|
|
1,148
|
|
|
1,126
|
|
|
Power
purchase
contract loss liability
|
|
1,184
|
|
|
1,226
|
|
|
Retirement
benefits
|
|
1,334
|
|
|
1,316
|
|
|
Lease
market
valuation liability
|
|
830
|
|
|
851
|
|
|
Other
|
|
|
1,614
|
|
|
1,616
|
|
|
|
|
|
|
|
8,869
|
|
|
8,861
|
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
31,797
|
|
$
|
31,841
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of these balance sheets.
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
|
|
March
31,
|
|
|
|
|
|
|
Restated
2006
|
|
2005
|
|
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$
|
221
|
|
$
|
160
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
148
|
|
|
143
|
|
|
Amortization
of regulatory assets
|
|
222
|
|
|
311
|
|
|
Deferral
of
new regulatory assets
|
|
(59
|
)
|
|
(60
|
)
|
|
Nuclear
fuel
and lease amortization
|
|
20
|
|
|
19
|
|
|
Deferred
purchased power and other costs
|
|
(125
|
)
|
|
(118
|
)
|
|
Deferred
income taxes and investment tax credits, net
|
|
6
|
|
|
(14
|
)
|
|
Deferred
rents
and lease market valuation liability
|
|
(38
|
)
|
|
(36
|
)
|
|
Accrued
compensation and retirement benefits
|
|
(19
|
)
|
|
(26
|
)
|
|
Commodity
derivative transactions, net
|
|
26
|
|
|
4
|
|
|
Income
from
discontinued operations
|
|
-
|
|
|
(19
|
)
|
|
Cash
collateral
|
|
(106
|
)
|
|
2
|
|
|
Decrease
(Increase) in operating assets -
|
|
|
|
|
|
|
|
|
Receivables
|
|
226
|
|
|
91
|
|
|
|
Materials
and
supplies
|
|
(52
|
)
|
|
7
|
|
|
|
Prepayments
and other current assets
|
|
(93
|
)
|
|
(106
|
)
|
|
Increase
(Decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
(114
|
)
|
|
61
|
|
|
|
Accrued
taxes
|
|
8
|
|
|
41
|
|
|
|
Accrued
interest
|
|
100
|
|
|
108
|
|
|
Electric
service prepayment programs
|
|
(14
|
)
|
|
(5
|
)
|
|
Other
|
|
|
(33
|
)
|
|
35
|
|
|
|
Net
cash
provided from operating activities
|
|
324
|
|
|
598
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
200
|
|
|
140
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Preferred
stock
|
|
(30
|
)
|
|
(98
|
)
|
|
Long-term
debt
|
|
(64
|
)
|
|
(236
|
)
|
Net
controlled
disbursement activity
|
|
(8
|
)
|
|
(30
|
)
|
Common
stock
dividend payments
|
|
(148
|
)
|
|
(135
|
)
|
|
|
Net
cash used
for financing activities
|
|
(50
|
)
|
|
(359
|
)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
Property
additions
|
|
(447
|
)
|
|
(229
|
)
|
Proceeds
from
asset sales
|
|
57
|
|
|
54
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
481
|
|
|
366
|
|
Investments
in
nuclear decommissioning trust funds
|
|
(484
|
)
|
|
(391
|
)
|
Cash
investments
|
|
103
|
|
|
27
|
|
Other
|
|
|
|
(20
|
)
|
|
(38
|
)
|
|
|
Net
cash used
for investing activities
|
|
(310
|
)
|
|
(211
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
(36
|
)
|
|
28
|
|
Cash
and cash
equivalents at beginning of period
|
|
64
|
|
|
53
|
|
Cash
and cash
equivalents at end of period
|
$
|
28
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to FirstEnergy
Corp. are an integral part of these statements.
|
|
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 March 31, 2006, and the related consolidated statements
of
income and comprehensive income and cash flows for each of the three-month
periods ended March 31, 2006 and 2005. 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
described in the
section entitled "Restatement of the Consolidated Statements of Cash Flows"
included in Note 1 to the consolidated interim financial statements, the Company
has restated its previously issued consolidated interim financial statements
for
the quarter ended March 31, 2006.
We
have previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2005, and the related consolidated statements of income, capitalization,
common stockholders’ equity, preferred stock, cash flows and taxes for the year
then ended, management’s assessment of the effectiveness of the Company’s
internal control over financial reporting as of December 31, 2005 and the
effectiveness of the Company’s internal control over financial reporting as of
December 31, 2005; 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 and conditional asset retirement obligations as of December
31, 2005 as discussed in Note 2(K) and Note 12 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 27, 2006,
we expressed unqualified opinions thereon. The consolidated financial statements
and management’s assessment of the effectiveness of internal control over
financial reporting referred to above are not presented herein. In our opinion,
the information set forth in the accompanying consolidated balance sheet as
of
December 31, 2005, is fairly stated in all material respects in relation to
the
consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May
8, 2006,
except as to Note 1, which is as of October 31, 2006
|
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE
SUMMARY
Net income in the first quarter of 2006 was $221 million, or basic and diluted
earnings of $0.67 per share of common stock, compared with net income of $160
million, or basic earnings of $0.49 per share of common stock ($0.48 diluted)
for the first quarter of 2005. Total revenues for the first quarter of 2006
were
$2.84 billion, up from $2.75 billion as adjusted to reflect certain
businesses divested in the first quarter of 2005. Certain businesses divested
in
the first quarter of 2005 have been classified as discontinued operations on
the
Consolidated Statements of Income (see Note 4). FirstEnergy’s earnings increase
was driven primarily by increased electric sales revenues, reduced financing
costs and reduced transition cost amortization for FirstEnergy's Ohio
Companies.
Total
electric
generation KWH sales were up by 2.1 percent over the prior-year quarter, mostly
due to the return of customers to the Ohio Companies from third-party suppliers
leaving the Ohio marketplace. Electric distribution deliveries were down
2.6 percent during the same time period, reflecting milder weather
conditions in 2006.
FirstEnergy's
generating fleet produced a record 20.1 billion KWH during the first quarter
of
2006 compared to 18.8 billion KWH in the first quarter of 2005.
FirstEnergy's non-nuclear fleet produced a record 13.4 billion KWH, while its
nuclear facilities produced 6.7 billion KWH.
Ohio
CBP - On
February 23, 2006, the CBP auction manager, National Economic Research
Associates, notified the PUCO that the CBP to potentially provide firm
generation service for the Ohio Companies’ 2007 and 2008 actual load
requirements could not proceed due to lack of interest, as there were no bidder
applications submitted. Additionally, on March 16, 2006, the PUCO denied
applications for rehearing filed by various parties regarding the PUCO’s rules
for the CBP.
On
May 3, 2006, the
Supreme Court of Ohio, in a ruling on certain appeals filed by the OCC and
NOAC,
issued an opinion affirming PUCO's June 2004 order with respect to the approval
of the rate stabilization charge, approval of the shopping credits, the grant
of
interest on shopping credit incentive deferral amounts and approval of
FirstEnergy's financial separation plan. It remanded the approval of the rate
stabilization plan pricing back to the PUCO for further consideration of the
issue as to whether the rate stabilization plan, as adopted by the PUCO,
provided for sufficient customer participation.
Wind
Power
Generation - In March 2006, FirstEnergy entered into multi-year agreements
to
purchase a combined 330 MW of wind power output from three wind power generation
projects. Two of the projects are being developed in West Virginia, and the
third is being developed in central Pennsylvania. The projects are anticipated
to be complete and operational in 2007. When combined with prior contracts,
these new contracts will bring the total wind power generation output available
to FirstEnergy to 360 MW.
Pennsylvania
Rate
Matters - On April 10, 2006, FirstEnergy's subsidiaries, Met-Ed and Penelec,
filed with the PPUC a comprehensive transition rate plan. The filing addresses
transmission, distribution and power supply issues while ensuring that customers
continue to pay below-market prices for generation through 2010.
Met-Ed
requested an
overall revenue increase of $216 million, or 19 percent, for 2007 if its
preferred approach of implementing accounting deferrals in its filing is
approved. Under an alternative proposed approach, the 2007 increase could be
up
to $269 million, or 24 percent. Met-Ed also has proposed changes in its
generation rates for the years 2008, 2009 and 2010 that could increase revenues
by up to $165 million per year.
Penelec
requested an
overall revenue increase of $157 million, or 15 percent, for 2007 if its
preferred approach of implementing accounting deferrals in its filing is
approved. Under an alternative proposed approach that assumes accounting
deferrals are not approved and instead adjusts rates to provide for appropriate
cost recovery, the 2007 increase could be up to $206 million, or 19 percent.
Penelec also has proposed changes in its generation rates for 2008, 2009 and
2010 that could increase revenues by up to $135 million per year.
Statutory
generation
rate caps imposed by Pennsylvania’s 1996 Electricity Generation Choice and
Competition Act expired as of year-end 2005. While Met-Ed's and Penelec's 1998
restructuring plans implemented under that act contain additional price caps
for
generation through 2010, Met-Ed and Penelec also incorrectly anticipated that
by
mid-2003 they would only serve 20 percent of their PLR customers’ generation
needs. However, Met-Ed and Penelec continue to serve virtually all of their
PLR
customers at these capped rates that have been and continue to be, well below
market prices.
The transmission portion of each transition rate plan filed with the PPUC
represents nearly one-half of the overall requested increase and reflects the
pass-through of federally mandated charges for transmission services from PJM.
Without regulatory relief, the charges Met-Ed and Penelec expect to pay in
2006
will exceed what they expect to collect from customers by an estimated $186
million (Met-Ed - $131 million; Penelec - $55 million).
With respect to the generation portion of customers' bills, the plan includes
a
four-year transition toward market-based generation rates. During this time,
customers would continue paying below-market prices for power. Under the
transition plan, the market-priced portion of the generation supply that Met-Ed
and Penelec procure for customers would gradually increase through
2010.
The
transition plan also proposes to defer, for future recovery, costs that Met-Ed
and Penelec are required to incur under federal law for power purchased from
NUGs for which there is currently inadequate recovery. The amount of these
costs
- above what Met-Ed and Penelec currently collect from customers - is expected
to total approximately $92 million in 2006. However, the deferral would
begin with costs incurred after new rates become effective.
Met-Ed and Penelec had filed on January 12, 2005 with the PPUC, a request for
deferral of transmission-related costs beginning January 1, 2005. As of March
31, 2006, the PPUC had taken no action on the request and neither company had
yet implemented deferral accounting for these costs. Met-Ed and Penelec sought
to consolidate this proceeding (and modified their request to provide deferral
of 2006 transmission-related costs only) with the April 10, 2006
comprehensive rate filing. On May 4, 2006, the PPUC approved the modified
request. Accordingly, Met-Ed and Penelec will implement deferral accounting
for
these costs in the second quarter of 2006, which will include $24 million
and $4 million, respectively, representing the amounts that were incurred
in the first quarter of 2006 - the deferrals of such amounts will be reflected
in the second quarter of 2006.
Nuclear
Outages -
Beaver Valley Unit 1 returned to service on April 19, 2006, restarting 11 days
ahead of schedule from a refueling and maintenance outage. The unit was the
first plant in the world to have a temporary opening cut in its containment
building and have its steam generators and reactor head replaced within a 65-day
time frame. The Beaver Valley Project also included replacing the turbine rotor,
rewinding the main generator, and replacing approximately one-third of the
fuel
assemblies.
Davis-Besse
returned
to service on April 27, 2006 from an outage to refuel the plant and to modify
it
to generate more electricity. Work performed during the outage, which began
on
March 6, 2006, included refurbishing the plant's turbine and rebuilding two
of
the four reactor coolant pumps. Generating capacity is expected to increase
by
approximately 11 MW to a gross output of about 946 MW.
Penn
RFP - On April
20, 2006 the PPUC approved Penn's PLR supply plan with modifications. The
approved plan encourages wholesale electric suppliers to participate in an
RFP
process to provide customers with generation service from January 1, 2007,
through May 13, 2008. Penn's PLR rates are currently capped at prices determined
through restructuring agreements that are set to expire at the end of 2006.
The
PPUC is obligated to approve a PLR plan with rates that reflect prevailing
market prices and that allow Penn to recover all reasonable costs for
service.
FIRSTENERGY’S
BUSINESS
FirstEnergy
is a
public utility holding company headquartered in Akron, Ohio that operates
primarily through two core business segments (see Results of
Operations).
· Regulated
Services
transmits and
distributes electricity through FirstEnergy's eight utility operating companies
that collectively comprise the nation’s fifth largest investor-owned electric
system, serving 4.5 million customers within 36,100 square miles of Ohio,
Pennsylvania and New Jersey. This business segment derives its revenue
principally from the delivery of electricity generated or purchased by the
Power
Supply Management Services segment in the states in which the utility
subsidiaries operate.
·
Power
Supply
Management Services
supplies all of the
electric power needs of end-use customers through retail and wholesale
arrangements, including regulated retail sales to meet the PLR requirements
of
FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail
sales to commercial and industrial businesses primarily in Ohio, Pennsylvania
and Michigan. This business segment owns and operates FirstEnergy's generating
facilities and purchases electricity from the wholesale market to meet sales
obligations. The segment's net income is primarily derived from electric
generation sales revenues less the related costs of electricity generation,
including purchased power, and net transmission, congestion and ancillary costs
charged by PJM and MISO to deliver energy to retail customers.
Other
operating
segments provide a wide range of services, including heating, ventilation,
air-conditioning, refrigeration, electrical and facility control systems,
high-efficiency electrotechnologies and telecommunication services. FirstEnergy
is in the process of divesting its remaining non-core businesses (see
Note 4). The assets and revenues for the other business operations are
below the quantifiable threshold for separate disclosure as “reportable
operating segments”.
FIRSTENERGY
INTRA-SYSTEM GENERATION ASSET TRANSFERS
On
May 13,
2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain
agreements implementing a series of intra-system generation asset transfers
that
were completed in the fourth quarter of 2005. The asset transfers resulted
in
the respective undivided ownership interests of the Ohio Companies and Penn
in
FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
FGCO, respectively. The generating plant interests transferred do not include
leasehold interests of CEI, TE and OE in certain of the plants that are
currently subject to sale and leaseback arrangements with non-affiliates.
On
October 24, 2005,
the Ohio Companies and Penn completed the intra-system transfer of non-nuclear
generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master
Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
the non-nuclear generation assets that it now owns. The asset transfers were
consummated pursuant to FGCO's purchase option under the Master Facility
Lease.
On
December 16,
2005, the Ohio Companies and Penn completed the intra-system transfer of their
respective ownership in the nuclear generation assets to NGC through, in the
case of OE and Penn, an asset spin-off by way of dividend and, in the case
of
CEI and TE, a sale at net book value. FENOC continues to operate and maintain
the nuclear generation assets.
These
transactions
were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were
approved by the PUCO and the PPUC, respectively, under applicable Ohio and
Pennsylvania electric utility restructuring legislation. Consistent with the
restructuring plans, generation assets that had been owned by the Ohio Companies
and Penn were required to be separated from the regulated delivery business
of
those companies through transfer to a separate corporate entity. The
transactions essentially completed the divestitures contemplated by the
restructuring plans by transferring the ownership interests to NGC and FGCO
without impacting the operation of the plants. The transfers were intercompany
transactions and, therefore, had no impact on our consolidated
results.
RESTATEMENT
OF CONSOLIDATED STATEMENT OF CASH FLOWS
As
further discussed
in Note 1 to the Consolidated Financial Statements, FirstEnergy is restating
its
Consolidated Statement of Cash Flows for the three months ended March 31,
2006.
This corrects a misclassification of a $78 million cash receipt from the
liquidation of cash investments (restricted cash related to the 2005 generation
asset transfers) in the first quarter of 2006. The cash receipt was previously
reported in cash flows from operating activities and should have been reported
in cash flows from investing activities. This correction resulted in a $78
million decrease in the previously reported cash flows from operating activities
and a corresponding increase in cash flows from investing activities in
FirstEnergy’s consolidated statement of cash flows for the three months ended
March 31, 2006. This resulted in revisions in the previously reported
Management’s Discussion and Analysis of Results of Operations only to Capital
Resources and Liquidity under the Cash Flows From Operating Activities and
Cash
Flows From Investing Activities sections. The correction does not change
FirstEnergy’s previously reported consolidated statements of income and
comprehensive income for the three months ended March 31, 2006 or its
consolidated balance sheet as of March 31, 2006.
The
financial
results discussed below include revenues and expenses from transactions among
FirstEnergy's business segments. A reconciliation of segment financial results
is provided in Note 13 to the consolidated financial statements. The FSG
business segment is included in “Other and Reconciling Adjustments” in this
discussion due to its immaterial impact on current period financial results,
but
is presented separately in segment information provided in Note 13 to the
consolidated financial statements. Net income (loss) by major business segment
was as follows:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
Net
Income (Loss)
|
|
(In
millions, except per share data)
|
|
By
Business Segment
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
211
|
|
$
|
236
|
|
$
|
(25
|
)
|
Power
supply
management services
|
|
|
40
|
|
|
(46
|
)
|
|
86
|
|
Other
and
reconciling adjustments*
|
|
|
(30
|
)
|
|
(30
|
)
|
|
-
|
|
Total
|
|
$
|
221
|
|
$
|
160
|
|
$
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
$
|
0.67
|
|
$
|
0.43
|
|
$
|
0.24
|
|
Discontinued
operations
|
|
|
-
|
|
|
0.06
|
|
|
(0.06
|
)
|
Net
Income
|
|
$
|
0.67
|
|
$
|
0.49
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
$
|
0.67
|
|
$
|
0.42
|
|
$
|
0.25
|
|
Discontinued
operations
|
|
|
-
|
|
|
0.06
|
|
|
(0.06
|
)
|
Net
Income
|
|
$
|
0.67
|
|
$
|
0.48
|
|
$
|
0.19
|
|
|
*
|
Represents
other operating segments and reconciling items including interest
expense
on holding company debt and corporate support services revenues and
expenses.
|
Net income in the first quarter of 2005 included after-tax earnings from
discontinued operations of $19 million ($0.06 per basic and diluted share)
resulting from FirstEnergy’s disposition of non-core assets and operations. In
the first quarter of 2005, discontinued operations included $17 million
from net gains on sales and $2 million from operations.
In the first quarter of 2005, earnings were increased by $0.02 per share from
the combined impact of $0.07 per share of gains from the sale of non-core
assets, offset by $0.04 per share of expense associated with the W. H. Sammis
Plant New Source Review settlement and $0.01 per share of expense related to
the
fine by the Nuclear Regulatory Commission regarding the Davis-Besse Nuclear
Power Station.
Financial results for FirstEnergy's major business segments in the first quarter
of 2006 and 2005 were as follows:
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Quarter 2006 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
935
|
|
$
|
1,576
|
|
$
|
-
|
|
$
|
2,511
|
|
Other
|
|
|
148
|
|
|
43
|
|
|
143
|
|
|
334
|
|
Internal
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
Revenues
|
|
|
1,083
|
|
|
1,619
|
|
|
143
|
|
|
2,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
976
|
|
|
-
|
|
|
976
|
|
Other
operating expenses
|
|
|
298
|
|
|
451
|
|
|
144
|
|
|
893
|
|
Provision
for
depreciation
|
|
|
96
|
|
|
46
|
|
|
6
|
|
|
148
|
|
Amortization
of regulatory assets
|
|
|
222
|
|
|
-
|
|
|
-
|
|
|
222
|
|
Deferral
of
new regulatory assets
|
|
|
(59
|
)
|
|
-
|
|
|
-
|
|
|
(59
|
)
|
General
taxes
|
|
|
140
|
|
|
45
|
|
|
8
|
|
|
193
|
|
Total
Expenses
|
|
|
697
|
|
|
1,518
|
|
|
158
|
|
|
2,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
386
|
|
|
101
|
|
|
(15
|
)
|
|
472
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
62
|
|
|
15
|
|
|
(34
|
)
|
|
43
|
|
Interest
expense
|
|
|
(94
|
)
|
|
(53
|
)
|
|
(18
|
)
|
|
(165
|
)
|
Capitalized
interest
|
|
|
3
|
|
|
4
|
|
|
-
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(2
|
)
|
|
-
|
|
|
-
|
|
|
(2
|
)
|
Total
Other
Income (Expense)
|
|
|
(31
|
)
|
|
(34
|
)
|
|
(52
|
)
|
|
(117
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
(benefit)
|
|
|
144
|
|
|
27
|
|
|
(37
|
)
|
|
134
|
|
Income
before
discontinued operations
|
|
|
211
|
|
|
40
|
|
|
(30
|
)
|
|
221
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
Income
(Loss)
|
|
$
|
211
|
|
$
|
40
|
|
$
|
(30
|
)
|
$
|
221
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Quarter 2005 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,082
|
|
$
|
1,355
|
|
$
|
-
|
|
$
|
2,437
|
|
Other
|
|
|
134
|
|
|
22
|
|
|
157
|
|
|
313
|
|
Internal
|
|
|
78
|
|
|
-
|
|
|
(78
|
)
|
|
-
|
|
Total
Revenues
|
|
|
1,294
|
|
|
1,377
|
|
|
79
|
|
|
2,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
895
|
|
|
-
|
|
|
895
|
|
Other
operating expenses
|
|
|
324
|
|
|
503
|
|
|
57
|
|
|
884
|
|
Provision
for
depreciation
|
|
|
123
|
|
|
13
|
|
|
7
|
|
|
143
|
|
Amortization
of regulatory assets
|
|
|
311
|
|
|
-
|
|
|
-
|
|
|
311
|
|
Deferral
of
new regulatory assets
|
|
|
(60
|
)
|
|
-
|
|
|
-
|
|
|
(60
|
)
|
General
taxes
|
|
|
146
|
|
|
32
|
|
|
7
|
|
|
185
|
|
Total
Expenses
|
|
|
844
|
|
|
1,443
|
|
|
71
|
|
|
2,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
450
|
|
|
(66
|
)
|
|
8
|
|
|
392
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
41
|
|
|
-
|
|
|
-
|
|
|
41
|
|
Interest
expense
|
|
|
(94
|
)
|
|
(7
|
)
|
|
(63
|
)
|
|
(164
|
)
|
Capitalized
interest
|
|
|
3
|
|
|
(3
|
)
|
|
-
|
|
|
-
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(7
|
)
|
|
-
|
|
|
-
|
|
|
(7
|
)
|
Total
Other
Income (Expense)
|
|
|
(57
|
)
|
|
(10
|
)
|
|
(63
|
)
|
|
(130
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
(benefit)
|
|
|
157
|
|
|
(30
|
)
|
|
(6
|
)
|
|
121
|
|
Income
before
discontinued operations
|
|
|
236
|
|
|
(46
|
)
|
|
(49
|
)
|
|
141
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
19
|
|
|
19
|
|
Net
Income
(Loss)
|
|
$
|
236
|
|
$
|
(46
|
)
|
$
|
(30
|
)
|
$
|
160
|
|
|
|
|
|
Power
|
|
|
|
|
|
Change
Between First Quarter 2006 and
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
First
Quarter 2005 Financial Results
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Increase
(Decrease)
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
(147
|
)
|
$
|
221
|
|
$
|
-
|
|
$
|
74
|
|
Other
|
|
|
14
|
|
|
21
|
|
|
(14
|
)
|
|
21
|
|
Internal
|
|
|
(78
|
)
|
|
-
|
|
|
78
|
|
|
-
|
|
Total
Revenues
|
|
|
(211
|
)
|
|
242
|
|
|
64
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
81
|
|
|
-
|
|
|
81
|
|
Other
operating expenses
|
|
|
(26
|
)
|
|
(52
|
)
|
|
87
|
|
|
9
|
|
Provision
for
depreciation
|
|
|
(27
|
)
|
|
33
|
|
|
(1
|
)
|
|
5
|
|
Amortization
of regulatory assets
|
|
|
(89
|
)
|
|
-
|
|
|
-
|
|
|
(89
|
)
|
Deferral
of
new regulatory assets
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
1
|
|
General
taxes
|
|
|
(6
|
)
|
|
13
|
|
|
1
|
|
|
8
|
|
Total
Expenses
|
|
|
(147
|
)
|
|
75
|
|
|
87
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(64
|
)
|
|
167
|
|
|
(23
|
)
|
|
80
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
21
|
|
|
15
|
|
|
(34
|
)
|
|
2
|
|
Interest
expense
|
|
|
-
|
|
|
(46
|
)
|
|
45
|
|
|
(1
|
)
|
Capitalized
interest
|
|
|
-
|
|
|
7
|
|
|
-
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
5
|
|
|
-
|
|
|
-
|
|
|
5
|
|
Total
Other
Income (Expense)
|
|
|
26
|
|
|
(24
|
)
|
|
11
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
(13
|
)
|
|
57
|
|
|
(31
|
)
|
|
13
|
|
Income
before
discontinued operations
|
|
|
(25
|
)
|
|
86
|
|
|
19
|
|
|
80
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
(19
|
)
|
|
(19
|
)
|
Net
Income
|
|
$
|
(25
|
)
|
$
|
86
|
|
$
|
-
|
|
$
|
61
|
|
Regulated
Services - First Quarter 2006 Compared to First Quarter
2005
Net
income decreased
$25 million (or 10.6%) to $211 million in the first quarter of 2006 compared
to
$236 million in the first quarter of 2005, primarily due to decreased
operating revenues partially offset by lower operating expenses and
taxes.
Revenues
-
The
decrease in
total revenues resulted from the following sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Distribution
services
|
|
$
|
935
|
|
$
|
1,082
|
|
$
|
(147
|
)
|
Transmission
services
|
|
|
94
|
|
|
92
|
|
|
2
|
|
Internal
revenues
|
|
|
-
|
|
|
78
|
|
|
(78
|
)
|
Other
|
|
|
54
|
|
|
42
|
|
|
12
|
|
Total
Revenues
|
|
$
|
1,083
|
|
$
|
1,294
|
|
$
|
(211
|
)
|
Decreases
in
distribution deliveries by customer class are summarized in the following
table:
Electric
Distribution Deliveries
|
|
|
|
Residential
|
|
|
(2.6
|
)%
|
Commercial
|
|
|
(2.1
|
)%
|
Industrial
|
|
|
(2.9
|
)%
|
Total
Distribution Deliveries
|
|
|
(2.6
|
)%
|
The
completion of
the Ohio Companies' generation transition cost recovery under their respective
transition plans and Penn's transition plan in 2005 was the primary reason
for
lower distribution unit prices, which, in conjunction with lower KWH deliveries,
resulted in lower distribution delivery revenues. The decreased deliveries
to
customers were primarily due to unseasonably mild weather during the first
quarter of 2006. The following table summarizes major factors contributing
to
the $147 million decrease in distribution service revenues in the first
quarter of 2006:
Sources
of Change in Distribution Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Changes
in
customer usage
|
|
$
|
(5
|
)
|
Changes
in
prices:
|
|
|
|
|
Rate
changes
|
|
|
(124
|
)
|
Rate
mix &
other
|
|
|
(18
|
)
|
|
|
|
|
|
Net
Decrease
in Distribution Revenues
|
|
$
|
(147
|
)
|
The
decrease in
internal revenues reflected the effect of the generation asset transfers
discussed above. The 2005 generation assets lease revenue from affiliates ceased
as a result of the transfers. Other revenues increased $14 million due in
part to higher payments received under a contract provision associated with
the
prior sale of TMI. Under the contract, additional payments are received if
subsequent energy prices rise above specified levels. These payments are passed
along to JCP&L, Met-Ed and Penelec customers, resulting in no net earnings
effect. Other revenues were also impacted by an increase in customer late
payment charges.
Expenses-
The
decrease in
revenues discussed above was partially offset by the following decreases in
total expenses:
|
·
|
Other
operating expenses were $26 million lower in 2006 due in part to
the
following factors:
|
|
1)
|
The
absence in
2006 of expenses for ancillary service refunds to third party suppliers
of
$7 million in 2005 due to the RCP, which provides that alternate
suppliers of ancillary services now bill customers directly for those
services;
|
|
|
2)
|
The
absence in
2006 of receivables factoring discount expenses of approximately
$5 million incurred in 2005;
and
|
|
3) |
A
$4 million
decrease in employee and contractor
costs.
|
|
·
|
Lower
depreciation expense of $27 million that resulted from the impact
of the
generation asset transfers.
|
|
·
|
Reduced
amortization of regulatory assets of $89 million principally due
to the
completion of Ohio generation transition cost recovery and Penn's
transition plan in 2005; and
|
|
·
|
General
taxes
decreased by $6 million primarily due to lower property taxes as
a result
of the generation asset transfers.
|
Other
Income
-
|
·
|
Higher
investment income reflects the impact of the generation asset transfers.
Interest income on the affiliated company notes receivable from the
power
supply management services segment in the first quarter of 2006 is
partially offset by the absence in 2006 of the majority of nuclear
decommissioning trust income which is now included in the power supply
management services segment; and
|
|
·
|
Subsidiaries'
preferred stock dividends decreased by $5 million in 2006 due to
redemption activity in 2005.
|
Power
Supply Management Services - First Quarter 2006 Compared to First Quarter
2005
Net
income for this
segment was $40 million in the first quarter of 2006 compared to a net loss
of $46 million in the same period last year. An improvement in the gross
generation margin was partially offset by higher depreciation, general taxes
and
interest expense resulting from the generation asset transfers.
Revenues
-
Electric generation sales revenues increased $199 million in the first quarter
of 2006 compared to the same period in 2005. This increase primarily resulted
from a 6.6% increase in retail KWH sales and higher unit prices resulting from
the 2006 rate stabilization and fuel recovery charges. Additional retail sales
reduced energy available for sales to the wholesale market. The transmission
revenues increase reflected new revenues under the MISO transmission rider
of
approximately $27 million that began in the first quarter of 2006.
An
increase in
reported segment revenues resulted from the following sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Electric
Generation Sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
1,239
|
|
$
|
980
|
|
$
|
259
|
|
Wholesale
|
|
|
235
|
|
|
295
|
|
|
(60
|
)
|
Total
Electric
Generation Sales
|
|
|
1,474
|
|
|
1,275
|
|
|
199
|
|
Retail
Transmission Rider
|
|
|
116
|
|
|
80
|
|
|
36
|
|
Other
Transmission
|
|
|
12
|
|
|
10
|
|
|
2
|
|
Other
|
|
|
17
|
|
|
12
|
|
|
5
|
|
Total
Revenues
|
|
$
|
1,619
|
|
$
|
1,377
|
|
$
|
242
|
|
The
following table
summarizes the price and volume factors contributing to changes in sales
revenues from retail and wholesale customers:
|
|
Increase
|
|
Source
of Change in Electric Generation Sales
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 6.6%
increase in customer usage
|
|
$
|
65
|
|
Change
in
prices
|
|
|
194
|
|
|
|
|
259
|
|
Wholesale:
|
|
|
|
|
Effect
of
15.7% decrease in KWH sales
|
|
|
(46
|
)
|
Change
in
prices
|
|
|
(14
|
)
|
|
|
|
(60
|
)
|
Net
Increase
in Electric Generation Sales
|
|
$
|
199
|
|
Expenses
-
Total
operating
expenses increased by $75 million. The increase was due to the following
factors:
|
·
|
Higher
fuel
and purchased power costs of $81 million, including increased fuel
costs of $49 million, of which, coal costs, contributed $41 million
as a result of increased generation output and higher coal prices
reflecting higher transportation costs. The increase in coal
transportation costs is primarily due to a change in the fuel mix
resulting from a greater use of western coal. Purchased power costs,
net
of the Ohio RCP fuel deferral of $21 million, increased $32 million
due to higher prices partially offset by lower volume. Factors
contributing to the higher costs are summarized in the following
table:
|
|
|
Increase
|
|
Source
of Change in Fuel and Purchased Power
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Fuel:
|
|
|
|
|
Change
due to
increased unit costs
|
|
$
|
32
|
|
Change
due to
volume consumed
|
|
|
17
|
|
|
|
|
49
|
|
Purchased
Power:
|
|
|
|
|
Change
due to
increased unit costs
|
|
|
77
|
|
Change
due to
volume purchased
|
|
|
(33
|
)
|
Decrease
in
NUG costs deferred
|
|
|
9
|
|
|
|
|
53
|
|
Ohio
RCP fuel
deferrals
|
|
|
(21
|
)
|
|
|
|
|
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
$
|
81
|
|
|
·
|
Higher
transmission expenses of $30 million related to the transmission
revenues
discussed above;
|
|
·
|
Increased
depreciation expenses of $33 million, which resulted principally
from the
generation asset transfers; and
|
|
·
|
Higher
general
taxes of $13 million due to additional property taxes resulting from
the
generation asset transfers.
|
Offsetting these higher costs were lower non-fuel operating expenses of
$52 million, which reflect the absence in 2006 of generating asset lease
rents of $78 million charged in 2005 due to the generation asset transfers.
Also
absent in 2006 were: (1) the 2005 accrual of an $8.5 million civil penalty
payable to the DOJ and $10 million for obligations to fund environmentally
beneficial projects in connection with the Sammis Plant settlement; and (2)
a
$3.5 million penalty related to the Davis-Besse outage.
Other
Income -
|
·
|
Investment
income in the first quarter of 2006 was higher by $15 million over
the
prior year period primarily due to nuclear decommissioning trust
investments acquired through the generation asset transfers;
and
|
|
|
|
|
·
|
Interest
expense increased by $46 million, primarily due to the interest expense
in
2006 on associated company notes payable used in connection with
the
generation asset transfers. This increase was partially offset by
an
additional $7 million of capitalized
interest.
|
Income Taxes
-
Income
taxes
increased as a result of higher taxable income.
Other
-
First Quarter 2006 Compared to First Quarter 2005
FirstEnergy’s
financial results from other operating segments and reconciling items, including
interest expense on holding company debt and corporate support services revenues
and expenses, resulted in no change to FirstEnergy’s net income in the first
quarter of 2006 compared to the same quarter of 2005. The effect of lower income
taxes due to allocations among the business segments offset the effect of the
absence of the results of the 2005 discontinued operations. The 2005 results
reflected the effect of discontinued operations, which included an after-tax
net
gain of $17 million from discontinued operations (see Note 4). The
following table summarizes the sources of income from discontinued operations
for the three months ended March 31, 2005:
|
|
(In
millions)
|
|
Discontinued
Operations (Net of tax)
|
|
|
|
Gain
on
sale:
|
|
|
|
Natural
gas business
|
|
$
|
5
|
|
Elliot-Lewis,
Spectrum and Power Piping
|
|
|
12
|
|
Reclassification
of operating income
|
|
|
2
|
|
Total
|
|
$
|
19
|
|
CAPITAL
RESOURCES AND LIQUIDITY
During 2006 and thereafter, FirstEnergy expects to meet its contractual
obligations primarily with a combination of cash from operations and funds
from
the capital markets. Borrowing capacity under credit facilities is available
to
manage working capital requirements.
Changes
in Cash Position
FirstEnergy's primary source of cash required for continuing operations as
a
holding company is cash from the operations of its subsidiaries. FirstEnergy
also has access to $2.0 billion of short-term financing under a revolving
credit facility which expires in 2010, subject to short-term debt limitations
under current regulatory approvals of $1.5 billion and to outstanding
borrowings by subsidiaries of FirstEnergy that are also parties to such
facility. In the first quarter of 2006, FirstEnergy received $148 million
of cash dividends from its subsidiaries and paid $148 million in cash
dividends to common shareholders. There are no material restrictions on the
payment of cash dividends by FirstEnergy's subsidiaries.
As of March 31, 2006, FirstEnergy had $28 million of cash and cash
equivalents compared with $64 million as of December 31, 2005. 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 primarily by its
regulated services and power supply management services businesses (see Results
of Operations above). Net cash provided from operating activities was
$324 million (as restated) in the first quarter of 2006 and
$598 million in the first quarter of 2005, summarized as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings(1)
|
|
$
|
388
|
|
$
|
359
|
|
Working
capital and other
|
|
|
(64)
|
|
|
239
|
|
Net
cash
provided from operating activities
|
|
$
|
324
|
|
$
|
598
|
|
(1) Cash
earnings are a
Non-GAAP measure (see reconciliation below).
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. FirstEnergy believes that cash earnings are a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Net
Income
(GAAP)
|
|
$
|
221
|
|
$
|
160
|
|
Non-Cash
Charges (Credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
148
|
|
|
143
|
|
Amortization
of regulatory assets
|
|
|
222
|
|
|
311
|
|
Deferral
of
new regulatory assets
|
|
|
(59
|
)
|
|
(60
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
20
|
|
|
19
|
|
Deferred
purchased power and other costs
|
|
|
(125
|
)
|
|
(118
|
)
|
Deferred
income taxes and investment tax credits
|
|
|
6
|
|
|
(14
|
)
|
Deferred
rents
and lease market valuation liability
|
|
|
(38
|
)
|
|
(36
|
)
|
Accrued
compensation and retirement benefits
|
|
|
(19
|
)
|
|
(26
|
)
|
Income
from
discontinued operations
|
|
|
-
|
|
|
(19
|
)
|
Other
non-cash
expenses
|
|
|
12
|
|
|
(1
|
)
|
Cash
Earnings
(Non-GAAP)
|
|
$
|
388
|
|
$
|
359
|
|
Net
cash provided
from operating activities decreased by $274 million in the first quarter of
2006
compared to the first quarter of 2005 primarily due to a $303 million decrease
in working capital, partially offset by a $29 million increase in cash
earnings described under "Results of Operations." The working capital decrease
primarily resulted from increased outflows of $175 million for payables and
$59
million for materials and supplies which reflected increased generation costs
as
discussed above and fuel inventory replacement activity due to increased fossil
fuel consumption and higher unit prices; $33 million from changes in accrued
taxes, and $108 million of cash collateral returned to suppliers. These
decreases were partially offset by an increase in cash provided from the
settlement of receivables balances of $135 million which reflects increased
electric sales revenues.
Cash
Flows
From Financing Activities
In
the first
quarters of 2006 and 2005, net cash used for financing activities was
$50 million and $359 million, respectively, primarily resulting from
the redemptions of debt and preferred stock as shown below.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Securities
Issued or Redeemed
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Redemptions
|
|
|
|
|
|
|
|
FMB
|
|
$
|
-
|
|
$
|
1
|
|
Pollution
control notes
|
|
|
54
|
|
|
-
|
|
Senior
secured
notes
|
|
|
10
|
|
|
20
|
|
Long-term
revolving credit
|
|
|
-
|
|
|
215
|
|
Preferred
stock
|
|
|
30
|
|
|
98
|
|
|
|
$
|
94
|
|
$
|
334
|
|
|
|
|
|
|
|
|
|
Short-term
Borrowings, Net
|
|
$
|
200
|
|
$
|
140
|
|
FirstEnergy
had approximately $931 million of short-term indebtedness as of March 31,
2006 compared to approximately $731 million as of December 31, 2005.
This increase was due primarily to increased capital spending including the
costs associated with the Davis-Besse and Beaver Valley Unit 1 refueling outages
during the first quarter of 2006 and lower customer cash receipts. Available
bank borrowing capability as of March 31, 2006 included the
following:
Borrowing
Capability
|
|
|
|
|
|
(In millions)
|
|
Short-term
credit facilities(1)
|
|
$
|
2,120
|
|
Accounts
receivable financing facilities
|
|
|
550
|
|
Utilized
|
|
|
(919
|
)
|
LOCs
|
|
|
(116
|
)
|
Net
|
|
$
|
1,635
|
|
|
|
|
|
|
(1)
A $2 billion
revolving credit facility that expires in 2010 is available in various
amounts to FirstEnergy and certain of its subsidiaries. A $100 million
revolving credit facility that expires in December 2006 and a $20
million
uncommitted line of credit facility that expires in September 2006
are
both available to FirstEnergy only.
|
As
of March 31,
2006, the Ohio Companies and Penn had the aggregate capability to issue
approximately $1.3 billion of additional FMB on the basis of property
additions and retired bonds under the terms of their respective mortgage
indentures. The issuance of FMB by OE and CEI are also subject to provisions
of
their senior note indentures generally limiting the incurrence of additional
secured debt, subject to certain exceptions that would permit, among other
things, the issuance of secured debt (including FMB) (i) supporting pollution
control notes or similar obligations, or (ii) as an extension, renewal or
replacement of previously outstanding secured debt. In addition, these
provisions would permit OE and CEI to incur additional secured debt not
otherwise permitted by a specified exception of up to $644 million and
$576 million, respectively, as of March 31, 2006. Under the provisions
of its senior note indenture, JCP&L may issue additional FMB only as
collateral for senior notes. As of March 31, 2006, JCP&L had the
capability to issue $625 million of additional senior notes upon the basis
of FMB collateral.
Based
upon
applicable earnings coverage tests in their respective charters, OE, Penn,
TE
and JCP&L could issue a total of $6 billion of preferred stock
(assuming no additional debt was issued) as of March 31, 2006. CEI, Met-Ed
and Penelec do not have similar restrictions and could issue up to the number
of
preferred stock shares authorized under their respective charters.
As
of March 31,
2006, approximately $1 billion of capacity remained unused under an
existing shelf registration statement, filed by FirstEnergy with the SEC in
2003, to support future securities issuances. The shelf registration provides
the flexibility to issue and sell various types of securities, including common
stock, debt securities, and share purchase contracts and related share purchase
units. As of April 26, 2006, a shelf registration statement filed by OE became
effective and provides, together with previously effective OE registration
statements, $1 billion of capacity to support future issuances of debt
securities by OE.
FirstEnergy's
working capital and short-term borrowing needs are met principally with a
$2 billion five-year revolving credit facility (included in the table
above). Borrowings under the facility are available to each borrower separately
and mature on the earlier of 364 days from the date of borrowing or the
commitment expiration date, June 16, 2010.
The
following table
summarizes the borrowing sub-limits for each borrower under the facility, as
well as the limitations on short-term indebtedness applicable to each borrower
under current regulatory approvals and applicable statutory and/or charter
limitations:
|
|
Revolving
|
|
Regulatory
and
|
|
|
|
Credit
Facility
|
|
Other
Short-Term
|
|
Borrower
|
|
Sub-Limit
|
|
Debt
Limitations1
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
$
|
2,000
|
|
$
|
1,500
|
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
43
|
|
CEI
|
|
|
250
|
|
|
500
|
|
TE
|
|
|
250
|
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
412
|
|
Met-Ed
|
|
|
250
|
|
|
300
|
|
Penelec
|
|
|
250
|
|
|
300
|
|
FES
|
|
|
-2
|
|
|
n/a
|
|
ATSI
|
|
|
-2
|
|
|
26
|
|
|
(1)
|
As
of March
31, 2006.
|
|
(2)
|
Borrowing
sub-limits for FES and ATSI may be increased to up to $250 million
and
$100
million,
respectively, by delivering notice to the administrative agent that
either
(i) such
borrower
has
senior unsecured debt ratings of at least BBB- by S&P and Baa3 by
Moody's
or
(ii)
FirstEnergy has guaranteed the obligations of such borrower under
the
facility.
|
The revolving credit facility, combined with an aggregate $550 million
($292 million unused as of March 31, 2006) of accounts receivable
financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended
to
provide liquidity to meet short-term working capital requirements for
FirstEnergy and its subsidiaries.
Under the revolving credit facility, borrowers may request the issuance of
LOCs
expiring up to one year from the date of issuance. The stated amount of
outstanding LOCs will count against total commitments available under the
facility and against the applicable borrower’s borrowing sub-limit. Total unused
borrowing capability under existing credit facilities and accounts receivable
financing facilities was $1.6 billion as of March 31, 2006.
The revolving credit facility contains financial covenants requiring each
borrower to maintain a consolidated debt to total capitalization ratio of no
more than 65%, measured at the end of each fiscal quarter.
As
of
March 31, 2006, FirstEnergy and its subsidiaries' debt to total
capitalization ratios (as defined under the revolving credit facility) were
as
follows:
Borrower
|
|
|
FirstEnergy
|
|
54
|
%
|
OE
|
|
33
|
%
|
Penn
|
|
35
|
%
|
CEI
|
|
52
|
%
|
TE
|
|
31
|
%
|
JCP&L
|
|
27
|
%
|
Met-Ed
|
|
39
|
%
|
Penelec
|
|
36
|
%
|
The
revolving credit
facility does not contain provisions that either restrict the ability to borrow
or accelerate repayment of outstanding advances as a result of any change in
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to the credit ratings of the company
borrowing the funds.
FirstEnergy's
regulated companies also 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 FirstEnergy's unregulated companies.
FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money
pool
agreements must repay the principal amount of the 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 first quarter of 2006 was approximately 4.58% for
both the regulated companies’ money pool and the unregulated companies' money
pool.
FirstEnergy’s
access
to capital markets and costs of financing are influenced by the ratings of
its
securities. The following table displays FirstEnergy’s and the Companies'
securities ratings as of March 31, 2006. The ratings outlook from S&P
on all securities is stable. The ratings outlook from Moody's and Fitch on
all
securities is positive.
Issuer
|
|
Securities
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB-
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BB+
|
|
|
|
|
|
|
|
|
|
TE
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB-
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba2
|
|
BB
|
|
|
|
|
|
|
|
|
|
Penn
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Senior
unsecured (1)
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
JCP&L
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
(1) Penn's
only senior
unsecured debt obligations are notes underlying pollution control revenue
refunding bonds issued by the Ohio Air Quality Development Authority to which
bonds this rating applies.
On
January 20,
2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable
Rate Series B preferred stock at $25.00 per share, plus accrued dividends to
the
date of redemption.
On
April 3, 2006,
NGC issued pollution control revenue refunding bonds ($60 million at 3.07%
and
$46.5 million at 3.25%). These bonds were used to redeem the following
Companies' pollution control notes (OE - $60 million at 7.05%, CEI - $27.7
million at 3.32%, TE - $18.8 million at 3.32%) on April 3, 2006. Also on
April 3, 2006, FGCO issued pollution control revenue refunding bonds ($90.1
million at 3.03% and $56.6 million at 3.10%) which were used to redeem the
following Companies' pollution control notes (OE - $14.8 million at 5.45%,
Penn
- $6.95 million at 5.45%, TE - $34.85 million at 3.18%, CEI - $47.5
million at 3.22%, $39.8 million at 3.20% and $2.8 million at 3.15%) in April
and
May 2006. These refinancings were undertaken in furtherance of FirstEnergy's
intra-system generation asset transfers (see Note 14). The proceeds from NGC's
and FGCO's refinancing issuances were used to repay a portion of their
associated company notes payable to OE, Penn, CEI, and TE, who then redeemed
their respective debt.
FirstEnergy
will
consider a common stock repurchase program later in 2006 after satisfactorily
finalizing its environmental compliance plans for its fossil
plants.
Cash
Flows
From Investing Activities
Net
cash flows used
in investing activities resulted principally from property additions. Regulated
services expenditures for property additions primarily include expenditures
supporting the distribution of electricity. Capital expenditures by the power
supply management services segment are principally generation-related. The
following table summarizes investments for the first quarter of 2006 and 2005
by
segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
Three
Months Ended March 31, 2006
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(195
|
)
|
$
|
136
|
|
$
|
(7
|
)
|
$
|
(66
|
)
|
Power
supply
management services
|
|
|
(244
|
)
|
|
(34
|
)
|
|
-
|
|
|
(278
|
)
|
Other
|
|
|
(1
|
)
|
|
16
|
|
|
(5
|
)
|
|
10
|
|
Inter-Segment
reconciling items
|
|
|
(7
|
)
|
|
30
|
|
|
1
|
|
|
24
|
|
Total
|
|
$
|
(447
|
)
|
$
|
148
|
|
$
|
(11
|
)
|
$
|
(310
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(141
|
)
|
$
|
21
|
|
$
|
3
|
|
$
|
(117
|
)
|
Power
supply
management services
|
|
|
(81
|
)
|
|
14
|
|
|
-
|
|
|
(67
|
)
|
Other
|
|
|
(3
|
)
|
|
1
|
|
|
(13
|
)
|
|
(15
|
)
|
Inter-Segment
reconciling items
|
|
|
(4
|
)
|
|
(8
|
)
|
|
-
|
|
|
(12
|
)
|
Total
|
|
$
|
(229
|
)
|
$
|
28
|
|
$
|
(10
|
)
|
$
|
(211
|
)
|
Net
cash used for
investing activities in the first quarter of 2006 (as restated) increased by
$99 million compared to the first quarter of 2005. The increase was
principally due to a $218 million increase in property additions which reflects
the replacement of the steam generators and reactor head at Beaver Valley Unit
1
and the distribution system Accelerated Reliability Improvement Program. The
increase in property additions was partially offset by $78 million from the
liquidation of cash investments (restricted cash related to the 2005 generation
asset transfers) and a $22 million decrease in net nuclear decommissioning
trust activities due to completion of the Ohio Companies' and Penn's transition
cost recovery for decommissioning at the end of 2005.
During
the remaining
three quarters of 2006, capital requirements for property additions and capital
leases are expected to be approximately $860 million. FirstEnergy and the
Companies have additional requirements of approximately $1.3 billion for
maturing long-term debt during the remainder of 2006. These cash requirements
are expected to be satisfied from a combination of internal cash, funds raised
in the long-term debt capital markets and short-term credit arrangements.
FirstEnergy's
capital spending for the period 2006-2010 is expected to be about
$6.7 billion (excluding nuclear fuel), of which $1.1 billion applies
to 2006. Investments for additional nuclear fuel during the 2006-2010 periods
are estimated to be approximately $769 million, of which about
$164 million applies to 2006. During the same period, FirstEnergy's nuclear
fuel investments are expected to be reduced by approximately $574 million
and $92 million, respectively, as the nuclear fuel is consumed.
GUARANTEES
AND OTHER ASSURANCES
As
part of normal
business activities, FirstEnergy enters into various agreements on behalf of
its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds, and LOCs. Some
of
the guaranteed contracts contain collateral provisions that are contingent
upon
FirstEnergy's credit ratings.
As
of March 31,
2006, FirstEnergy's maximum exposure to potential future payments under
outstanding guarantees and other assurances totaled approximately
$3.3 billion, as summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
Exposure
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees of Subsidiaries:
|
|
|
|
Energy
and
Energy-Related Contracts(1)
|
|
$
|
906
|
|
Other(2)
|
|
|
884
|
|
|
|
|
1,790
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
136
|
|
LOC(3)(4)
|
|
|
1,340
|
|
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
$
|
3,266
|
|
|
(1)
|
Issued
for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
Issued
for
various terms.
|
|
(3)
|
Includes
$116
million issued for various terms under LOC capacity available under
FirstEnergy’s revolving credit agreement and $604 million outstanding in
support of pollution control revenue bonds issued with various
maturities.
|
|
(4)
|
Includes
approximately $194 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
in
connection with the sale and leaseback of Beaver Valley Unit 2 by
OE and
$134 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 commodity 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 to fulfill the obligations of
its
subsidiaries directly involved in these energy and energy-related transactions
or financings where the law might otherwise limit the counterparties' claims.
If
demands of a counterparty were to exceed the ability of a subsidiary to satisfy
existing obligations, 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 and energy-related
contracts 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 posting of cash collateral
or provision of an LOC may be required of the subsidiary. As of March 31,
2006, FirstEnergy's maximum exposure under these collateral provisions was
$456
million.
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.
FirstEnergy
has
guaranteed the obligations of the operators of the TEBSA project 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 also provided an LOC ($36 million as of March 31,
2006), which is renewable and declines yearly based upon the senior outstanding
debt of TEBSA.
OFF-BALANCE
SHEET ARRANGEMENTS
FirstEnergy
has
obligations that are not included on its Consolidated Balance Sheets related
to
the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley
Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating
lease payments. The present value of these sale and leaseback operating lease
commitments, net of trust investments, total $1.3 billion as of
March 31, 2006.
FirstEnergy has equity ownership interests in certain 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 Guarantees
and
Other Assurances 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 members of senior management,
provides general oversight to risk management activities throughout the Company.
Commodity
Price Risk
FirstEnergy
is
exposed to financial and market risks resulting from the fluctuation of interest
rates and commodity prices primarily due to fluctuations in electricity, energy
transmission, natural gas, coal, nuclear fuel and emission allowance prices.
To
manage the volatility relating to these exposures, FirstEnergy uses a variety
of
non-derivative and derivative instruments, including forward contracts, options,
futures contracts and swaps. The derivatives are used principally for hedging
purposes. Derivatives that fall within the scope of SFAS 133 must be
recorded at their fair value and marked to market. The majority of FirstEnergy's
derivative hedging contracts qualify for the normal purchase and normal sale
exception under SFAS 133 and are therefore excluded from the table below.
Contracts that are not exempt from such treatment include power purchase
agreements with NUG entities that were structured pursuant to the Public Utility
Regulatory Policies Act of 1978. These non-trading contracts are adjusted to
fair value at the end of each quarter, with a corresponding regulatory asset
recognized for above-market costs. The change in the fair value of commodity
derivative contracts related to energy production during the first quarter
of
2006 is summarized in the following table:
Increase
(Decrease) in the Fair Value of Commodity Derivative
Contracts
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Change
in the Fair Value of Commodity Derivative
Contracts:
|
|
|
|
|
|
|
|
Outstanding
net liability as of January 1, 2006
|
|
$
|
(1,170
|
)
|
$
|
(3
|
)
|
$
|
(1,173
|
)
|
New
contract
value when entered
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
|
122
|
|
|
(7
|
)
|
|
115
|
|
Change
in
techniques/assumptions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
|
(81
|
)
|
|
5
|
|
|
(76
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net liability as of March 31, 2006(1)
|
|
$
|
(1,129
|
)
|
$
|
(5
|
)
|
$
|
(1,134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Assets as of March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
Interest
Rate
Swaps(2)
|
|
|
-
|
|
|
(16
|
)
|
|
(16
|
)
|
Net
Liabilities - Derivatives Contracts as of March 31,
2006
|
|
$
|
(1,129
|
)
|
$
|
(21
|
)
|
$
|
(1,150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts:(3)
|
|
|
|
|
|
|
|
|
|
|
Income
Statement Effects (Pre-Tax)
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
(2
|
)
|
Balance
Sheet
Effects:
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Pre-Tax)
|
|
$
|
-
|
|
$
|
(2
|
)
|
$
|
(2
|
)
|
Regulatory
Asset (net)
|
|
$
|
(43
|
)
|
$
|
-
|
|
$
|
(43
|
)
|
(1) Includes
$1,140
million in non-hedge commodity derivative contracts (primarily with NUGs),
which
are offset by a regulatory asset.
(2) Interest
rate swaps
are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements
below).
(3) Represents
the
change in value of existing contracts, settled contracts and changes in
techniques/assumptions.
Derivatives
are
included on the Consolidated Balance Sheet as of March 31, 2006 as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Current-
|
|
|
|
|
|
|
|
Other
assets
|
|
$
|
5
|
|
$
|
12
|
|
$
|
17
|
|
Other
liabilities
|
|
|
(9
|
)
|
|
(15
|
)
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
|
46
|
|
|
30
|
|
|
76
|
|
Other
noncurrent liabilities
|
|
|
(1,171
|
)
|
|
(48
|
)
|
|
(1,219
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
assets
(liabilities)
|
|
$
|
(1,129
|
)
|
$
|
(21
|
)
|
$
|
(1,150
|
)
|
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:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Fair
Value by Contract Year
|
|
2006(1)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Prices
actively quoted(2)
|
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(4
|
)
|
Other
external
sources(3)
|
|
|
(281
|
)
|
|
(284
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(565
|
)
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
(246
|
)
|
|
(166
|
)
|
|
(137
|
)
|
|
(16
|
)
|
|
(565
|
)
|
Total(4)
|
|
$
|
(283
|
)
|
$
|
(286
|
)
|
$
|
(246
|
)
|
$
|
(166
|
)
|
$
|
(137
|
)
|
$
|
(16
|
)
|
$
|
(1,134
|
)
|
(1) For
the last three
quarters of 2006.
(2) Exchange
traded.
(3) Broker
quote
sheets.
|
(4)
|
Includes
$1,140 million in non-hedge commodity derivative contracts (primarily
with
NUGs), which are offset by a regulatory
asset.
|
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 its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of March 31, 2006. Based on derivative contracts held as of
March 31, 2006, an adverse 10% change in commodity prices would decrease
net income by approximately $5 million during the next 12 months.
Interest
Rate Swap Agreements- Fair Value Hedges
FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part
of
its ongoing effort to manage the interest rate risk associated with 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. During the first quarter of 2006, FirstEnergy unwound
swaps with a total notional amount of $350 million for which FirstEnergy
paid $1 million in cash. The loss will be recognized over the remaining
maturity of each respective hedged security as increased interest expense.
As of
March 31, 2006, the debt underlying the $750 million outstanding
notional amount of interest rate swaps had a weighted average fixed interest
rate of 5.74%, which the swaps have converted to a current weighted average
variable rate of 6.24%.
|
|
March
31, 2006
|
|
December
31, 2005
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Interest
Rate Swaps
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
(Fair
value
hedges)
|
|
$
|
100
|
|
|
2008
|
|
$
|
(4
|
)
|
$
|
100
|
|
|
2008
|
|
$
|
(3
|
)
|
|
|
|
50
|
|
|
2010
|
|
|
(1
|
)
|
|
50
|
|
|
2010
|
|
|
-
|
|
|
|
|
-
|
|
|
2011
|
|
|
-
|
|
|
50
|
|
|
2011
|
|
|
-
|
|
|
|
|
300
|
|
|
2013
|
|
|
(12
|
)
|
|
450
|
|
|
2013
|
|
|
(4
|
)
|
|
|
|
150
|
|
|
2015
|
|
|
(13
|
)
|
|
150
|
|
|
2015
|
|
|
(9
|
)
|
|
|
|
-
|
|
|
2016
|
|
|
-
|
|
|
150
|
|
|
2016
|
|
|
-
|
|
|
|
|
50
|
|
|
2025
|
|
|
(2
|
)
|
|
50
|
|
|
2025
|
|
|
(1
|
)
|
|
|
|
100
|
|
|
2031
|
|
|
(8
|
)
|
|
100
|
|
|
2031
|
|
|
(5
|
)
|
|
|
$
|
750
|
|
|
|
|
$
|
(40
|
)
|
$
|
1,100
|
|
|
|
|
$
|
(22
|
)
|
Forward
Starting Swap Agreements - Cash Flow Hedges
FirstEnergy
utilizes
forward starting swap agreements (forward swaps) in order to hedge a portion
of
the consolidated interest rate risk associated with the anticipated future
issuances of fixed-rate, long-term debt securities for one or more of its
consolidated subsidiaries in 2006 through 2008. These derivatives are treated
as
cash flow hedges, protecting against the risk of changes in future interest
payments resulting from changes in benchmark U.S. Treasury rates between the
date of hedge inception and the date of the debt issuance. During the first
quarter of 2006, FirstEnergy entered into forward swaps with a total notional
amount of $525 million and terminated forward swaps with a total notional amount
of $500 million from which FirstEnergy received $16 million in cash. The gain
associated with the ineffective portion of the terminated hedges ($5 million)
was recognized in earnings in the first quarter of 2006, with the remainder
to
be recognized over the terms of the respective forward swaps. As of
March 31, 2006, FirstEnergy had outstanding forward swaps with an aggregate
notional amount of $1 billion and an aggregate fair value of
$25 million.
|
|
March
31, 2006
|
|
December
31, 2005
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Forward
Starting Swaps
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
(Cash
flow
hedges)
|
|
$
|
25
|
|
|
2015
|
|
$
|
1
|
|
$
|
25
|
|
|
2015
|
|
$
|
-
|
|
|
|
|
250
|
|
|
2016
|
|
|
8
|
|
|
600
|
|
|
2016
|
|
|
2
|
|
|
|
|
50
|
|
|
2017
|
|
|
1
|
|
|
25
|
|
|
2017
|
|
|
-
|
|
|
|
|
125
|
|
|
2018
|
|
|
4
|
|
|
275
|
|
|
2018
|
|
|
1
|
|
|
|
|
50
|
|
|
2020
|
|
|
2
|
|
|
50
|
|
|
2020
|
|
|
-
|
|
|
|
|
500
|
|
|
2036
|
|
|
9
|
|
|
-
|
|
|
2036
|
|
|
-
|
|
|
|
$
|
1,000
|
|
|
|
|
$
|
25
|
|
$
|
975
|
|
|
|
|
$
|
3
|
|
Equity
Price Risk
Included in nuclear decommissioning trusts are marketable equity securities
carried at their market value of approximately $1.1 billion as of March 31,
2006 and December 31, 2005. A hypothetical 10% decrease in prices quoted by
stock exchanges would result in a $113 million reduction in fair value as
of March 31, 2006.
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 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 March 31, 2006, the largest credit concentration with one
party (currently rated investment grade) represented 7.1% of FirstEnergy's
total
credit risk. Within FirstEnergy's unregulated energy subsidiaries, 99% of credit
exposures, net of collateral and reserves, were with investment-grade
counterparties as of March 31, 2006.
Outlook
State
Regulatory
Matters
In
Ohio, New Jersey
and Pennsylvania, laws applicable to electric industry restructuring contain
similar provisions that are reflected in the Companies' respective state
regulatory plans. These provisions include:
·
|
restructuring the electric generation business and allowing the Companies'
customers to select a competitive
electric generation
supplier other than the Companies;
|
|
|
·
|
establishing
or defining
the PLR obligations to customers in the Companies' service
areas;
|
|
|
·
|
providing
the
Companies with the opportunity to recover potentially stranded investment
(or transition costs)
not otherwise recoverable in a competitive generation
market;
|
|
|
·
|
itemizing (unbundling) the price of electricity into its component
elements - including generation, transmission, distribution
and stranded costs recovery charges;
|
|
|
·
|
continuing
regulation of the Companies' transmission and distribution systems;
and
|
|
|
·
|
requiring
corporate separation of regulated and unregulated business
activities.
|
The
Companies and
ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and
NJBPU
have authorized for recovery from customers in future periods or for which
authorization is probable. Without the probability of such authorization, costs
currently recorded as regulatory assets would have been charged to income as
incurred. Regulatory assets that do not earn a current return totaled
approximately $237 million as of March 31, 2006. The following table
discloses the regulatory assets by company and by source:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
757
|
|
$
|
775
|
|
$
|
(18
|
)
|
CEI
|
|
|
858
|
|
|
862
|
|
|
(4
|
)
|
TE
|
|
|
276
|
|
|
287
|
|
|
(11
|
)
|
JCP&L
|
|
|
2,168
|
|
|
2,227
|
|
|
(59
|
)
|
Met-Ed
|
|
|
308
|
|
|
310
|
|
|
(2
|
)
|
ATSI
|
|
|
29
|
|
|
25
|
|
|
4
|
|
Total
|
|
$
|
4,396
|
|
$
|
4,486
|
|
$
|
(90
|
)
|
|
*
|
Penn
had net
regulatory liabilities of approximately $64 million and $59 million
as of
March 31, 2006 and December 31, 2005.
Penelec
had
net regulatory liabilities of approximately $156 million and
$163 million as of March 31, 2006 and December 31,
2005.
These
net regulatory liabilities are included in Other Noncurrent Liabilities
on
the Consolidated Balance Sheets.
|
Regulatory
assets by
source are as follows:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
3,470
|
|
$
|
3,576
|
|
$
|
(106
|
)
|
Customer
shopping incentives
|
|
|
662
|
|
|
884
|
|
|
(222
|
)
|
Customer
receivables for future income taxes
|
|
|
215
|
|
|
217
|
|
|
(2
|
)
|
Societal
benefits charge
|
|
|
15
|
|
|
29
|
|
|
(14
|
)
|
Loss
on
reacquired debt
|
|
|
40
|
|
|
41
|
|
|
(1
|
)
|
Employee
postretirement benefits costs
|
|
|
53
|
|
|
55
|
|
|
(2
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
--
|
|
|
|
|
and
spent fuel
disposal costs
|
|
|
(129
|
)
|
|
(126
|
)
|
|
(3
|
)
|
Asset
removal
costs
|
|
|
(164
|
)
|
|
(365
|
)
|
|
201
|
|
Property
losses and unrecovered plant costs
|
|
|
27
|
|
|
29
|
|
|
(2
|
)
|
MISO
transmission costs
|
|
|
90
|
|
|
91
|
|
|
(1
|
)
|
RCP
fuel
recovery
|
|
|
22
|
|
|
-
|
|
|
22
|
|
RCP
distribution costs
|
|
|
40
|
|
|
-
|
|
|
40
|
|
JCP&L
reliability costs
|
|
|
21
|
|
|
23
|
|
|
(2
|
)
|
Other
|
|
|
34
|
|
|
32
|
|
|
2
|
|
Total
|
|
$
|
4,396
|
|
$
|
4,486
|
|
$
|
(90
|
)
|
Reliability
Initiatives
FirstEnergy
is
proceeding with the implementation of the recommendations that were issued
from
various entities, including governmental, industry and ad hoc liability entities
(PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) in
late
2003 and early 2004, regarding enhancements to regional reliability that were
to
be completed subsequent to 2004. FirstEnergy will continue to periodically
assess the FERC-ordered Reliability Study recommendations for forecasted 2009
system conditions, recognizing revised load forecasts and other changing system
conditions which may impact the recommendations. Thus far, implementation of
the
recommendations has not required, nor is expected to require, substantial
investment in new, or material upgrades to existing, equipment. The FERC or
other applicable government agencies and reliability coordinators, however,
may
take a different view as to recommended enhancements or may recommend additional
enhancements in the future as the result of adoption of mandatory reliability
standards pursuant to EPACT that could require additional, material
expenditures. Finally, the PUCO is continuing to review our filing that
addressed upgrades to control room computer hardware and software and
enhancements to the training of control room operators before determining the
next steps, if any, in the proceeding.
As
a result of
outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L's service reliability. In 2004, the NJBPU
adopted an MOU that set out specific tasks and a timetable for completion of
actions related to service reliability to be performed by JCP&L and also
approved a Stipulation that incorporates the final report of a Special
Reliability Master who made recommendations on appropriate courses of action
necessary to ensure system-wide reliability. JCP&L continues to file
compliance reports reflecting activities associated with the MOU and
Stipulation.
In
May 2004, the
PPUC issued an order approving revised reliability benchmarks and standards,
including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed,
Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC
on
May 26, 2004, due to their implementation of automated outage management
systems following restructuring. On December 30, 2005, the ALJ recommended
that
the PPUC adopt the Joint Petition for Settlement among the parties involved
in
the three Companies’ request to amend the distribution reliability benchmarks,
thereby eliminating the need for full litigation. The ALJ’s recommendation,
adopting the revised benchmarks and standards, was approved by the PPUC on
February 9, 2006.
EPACT
provides for
the creation of an ERO to establish and enforce reliability standards for the
bulk power system, subject to FERC review. On February 3, 2006, the FERC
adopted a rule establishing certification requirements for the ERO, as well
as
regional entities envisioned to assume monitoring responsibility for the new
reliability standards. The FERC issued an order on rehearing on March 30,
2006, providing certain clarifications and essentially affirming the
rule.
The
NERC has been
preparing the implementation aspects of reorganizing its structure to meet
the
FERC’s certification requirements for the ERO. The NERC made a filing with the
FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
approval of delegation agreements with regional entities. The new FERC rule
referred to above, further provides for reorganizing regional reliability
organizations (regional entities) that would replace the current regional
councils and for rearranging the relationship with the ERO. The “regional
entity” may be delegated authority by the ERO, subject to FERC approval, for
enforcing reliability standards adopted by the ERO and approved by the FERC.
NERC also made a parallel filing with the FERC April 4, 2006 seeking approval
of
mandatory reliability standards. These
reliability
standards are based with some modifications, on the current NERC Version O
reliability standards with some additional standards. On May 2, 2006, the
NERC Board of Trustees adopted eight new cyber security standards and thirteen
additional reliability standards. These standards will become effective on
June 1, 2006 and will be filed with the FERC and relevant Canadian
authorities for approval. The
two filings are
subject to review and acceptance by the FERC.
The
ERO filing was
noticed on April 7, 2006 and comments and interventions were filed on
May 4, 2006. There is no fixed time for the FERC to act on this filing. The
reliability standards filing was noticed by FERC on April 18, 2006. In that
notice FERC announced its intent to treat the proposed reliability standards
as
a NOPR and issue a NOPR in July 2006. Prior to that time, the FERC staff will
release a preliminary assessment of the proposed reliability standards. FERC
also intends to hold a technical conference on the proposed reliability
standards. A comment period will be set after the Staff assessment is released
and the technical conference is held. NERC has requested an effective date
of
January 1, 2007 for the reliability standards.
The
ECAR,
Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
councils have completed the consolidation of these regions into a single new
regional reliability organization known as ReliabilityFirst Corporation.
ReliabilityFirst began operations as a regional reliability council under NERC
on January 1, 2006 and intends to file and obtain certification consistent
with the final rule as a “regional entity” under the ERO during 2006. All of
FirstEnergy’s facilities are located within the ReliabilityFirst
region.
FirstEnergy
believes that it is in compliance with all current NERC reliability standards.
However, it is expected that the FERC will adopt stricter reliability standards
than those contained in the current NERC standards. The financial impact of
complying with the new standards cannot be determined at this time. However,
EPACT requires that all prudent costs incurred to comply with the new
reliability standards be recovered in rates. If FirstEnergy is unable to meet
the reliability standards for the bulk power system in the future, it could
have
a material adverse effect on the Company’s and its subsidiaries’ financial
condition, results of operations and cash flows.
See
Note 11 to
the consolidated financial statements for a more detailed discussion of
reliability initiatives.
Ohio
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On
August 5, 2004, the Ohio Companies accepted the RSP as modified and approved
by
the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP
was
intended to establish generation service rates beginning January 1, 2006,
in response to PUCO concerns about price and supply uncertainty following the
end of the Ohio Companies' transition plan market development period. In October
2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn
the original June 9, 2004 PUCO order in this proceeding as well as the
associated entries on rehearing. On September 28, 2005, the Ohio Supreme
Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court
of
Ohio issued an opinion affirming that order with respect to the approval of
the
rate stabilization charge, approval of the shopping credits, the grant of
interest on shopping credit incentive deferral amounts, and approval of
FirstEnergy’s financial separation plan. It remanded the approval of the RSP
pricing back to the PUCO for further consideration of the issue as to whether
the RSP, as adopted by the PUCO, provided for sufficient customer participation
in the competitive marketplace.
Under provisions of the RSP, the PUCO had required the Ohio Companies to
undertake a CBP to secure generation and allow for customer pricing
participation in the competitive marketplace. Any acceptance of future
competitive bid results would terminate the RSP pricing, with no accounting
impacts to the RSP, and not until 12 months after the PUCO authorizes such
termination. On December 9, 2004, the PUCO rejected the auction price
results from the CBP for the generation supply period beginning January 1,
2006
and issued an entry stating that the pricing under the approved revised RSP
would take effect on January 1, 2006. On February 23, 2006 the CBP
auction manager, National Economic Research Associates, notified the PUCO that
a
subsequent CBP to potentially provide firm generation service for the Ohio
Companies' 2007 and 2008 actual load requirements could not proceed due to
lack
of interest, as there were no bidder applications submitted. Additionally,
on
March 20, 2006, the PUCO denied applications for rehearing filed by various
parties regarding the PUCO's rules for the CBP. The above May 3, 2006
Supreme Court of Ohio opinion may require the PUCO to reconsider this customer
pricing process.
On
January 4, 2006,
the PUCO approved, with modifications, the Ohio Companies' RCP to supplement
the
RSP to provide customers with more certain rate levels than otherwise available
under the RSP during the plan period. Major provisions of the RCP
include:
|
·
|
Maintaining
the existing level of base distribution rates through December 31,
2008 for OE and TE, and April 30, 2009 for
CEI;
|
|
·
|
Deferring
and
capitalizing for future recovery (over a 25-year period) with carrying
charges certain distribution costs to be incurred during the period
January 1, 2006 through December 31, 2008, not to exceed
$150 million in each of the three
years;
|
|
·
|
Adjusting
the
RTC and extended RTC recovery periods and rate levels so that full
recovery of authorized costs will occur as of December 31, 2008 for
OE and TE and as of December 31, 2010 for
CEI;
|
|
·
|
Reducing
the
deferred shopping incentive balances as of January 1, 2006 by up to
$75 million for OE, $45 million for TE, and $85 million for CEI
by accelerating the application of each respective company's accumulated
cost of removal regulatory liability;
and
|
|
·
|
Recovering
increased fuel costs (compared to a 2002 baseline) of up to $75 million,
$77 million, and $79 million, in 2006, 2007, and 2008,
respectively, from all OE and TE distribution and transmission customers
through a fuel recovery mechanism. OE, TE, and CEI may defer and
capitalize (for recovery over a 25-year period) increased fuel costs
above
the amount collected through the fuel recovery mechanism (in lieu
of
implementation of the GCAF rider).
|
The
following table
provides the estimated net amortization of regulatory transition costs and
deferred shopping incentives (including associated carrying charges) under
the
RCP for the period 2006 through 2010:
Amortization
|
|
|
|
|
|
|
|
Total
|
|
Period
|
|
OE
|
|
CEI
|
|
TE
|
|
Ohio
|
|
|
|
(In
millions)
|
|
2006
|
|
$
|
172
|
|
$
|
97
|
|
$
|
83
|
|
$
|
352
|
|
2007
|
|
|
180
|
|
|
113
|
|
|
90
|
|
|
383
|
|
2008
|
|
|
206
|
|
|
130
|
|
|
108
|
|
|
444
|
|
2009
|
|
|
-
|
|
|
211
|
|
|
-
|
|
|
211
|
|
2010
|
|
|
-
|
|
|
263
|
|
|
-
|
|
|
263
|
|
Total
Amortization
|
|
$
|
558
|
|
$
|
814
|
|
$
|
281
|
|
$
|
1,653
|
|
The
PUCO’s January
4, 2006 approval of the RCP also included approval of the Ohio
Companies’
supplemental
stipulation which was filed with the PUCO on November 4, 2005 and which was
an
additional component of the RCP filed on September 9, 2005. On
January 10, 2006, the Ohio Companies filed a Motion for Clarification of
the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
related to distribution deferrals, including requirements of the review process,
timing for recognizing certain deferrals and definitions of the types of
qualified expenditures. The Ohio Companies also sought confirmation that the
list of deferrable distribution expenditures originally included in the revised
stipulation fall within the PUCO order definition of qualified expenditures.
On
January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
and denying in part, the Ohio Companies’ previous requests and clarifying issues
referred to above. The PUCO granted the Ohio Companies’ requests to:
|
·
|
Recognize
fuel
and distribution deferrals commencing January 1,
2006;
|
|
|
|
|
·
|
Recognize
distribution deferrals on a monthly basis prior to review by the
PUCO
Staff;
|
|
·
|
Clarify
that
the types of distribution expenditures included in the Supplemental
Stipulation may be deferred; and
|
|
|
|
|
·
|
Clarify
that
distribution expenditures do not have to be “accelerated” in order to be
deferred.
|
|
|
|
The
PUCO approved the Ohio Companies’ methodology for determining distribution
deferral amounts, but denied the Motion in that the PUCO Staff must verify
the
level of distribution expenditures contained in current rates, as opposed to
simply accepting the amounts contained in the Ohio Companies’ Motion. On
February 3, 2006, several other parties filed applications for rehearing on
the
PUCO's January 4, 2006 Order. The Ohio Companies responded to the
applications for rehearing on February 13, 2006. In an Entry on Rehearing
issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
Certain of these parties have subsequently filed their notices of appeal with
the Supreme Court of Ohio alleging various errors made by the PUCO in its order
approving the RCP.
On
December 30,
2004, the Ohio Companies filed with the PUCO two applications related to the
recovery of transmission and ancillary service related costs. The first
application sought recovery of these costs beginning January 1, 2006. The
Ohio Companies requested that these costs be recovered through a rider that
would be effective on January 1, 2006 and adjusted each July 1
thereafter. The parties reached a settlement agreement that was approved by
the
PUCO on August 31, 2005. The incremental transmission and ancillary service
revenues expected to be recovered from January through June 30, 2006 are
approximately $66 million. This amount includes the recovery of the 2005
deferred MISO expenses as described below. On May 1, 2006, the Ohio
Companies filed a modification to the rider to determine revenues from July
2006
through June 2007.
The
second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO granted the
accounting authority for the Ohio Companies to defer incremental transmission
and ancillary service-related charges incurred as a participant in MISO, but
only for those costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
to accrue carrying charges on the deferred balances. On August 31, 2005,
the OCC appealed the PUCO's decision. All briefs have been filed. On March
20,
2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal
of the Ohio Companies' case with a similar case involving Dayton Power &
Light Company. Oral arguments are currently scheduled for May 10, 2006.
On
January 20,
2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred
costs through the rider during the period January 1, 2006 through June 30,
2006. The PUCO denied the OCC's application on February 6, 2006. On March
23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's
brief is expected to be filed during the second quarter of 2006. The briefs
of
the PUCO and the Ohio Companies will be due within thirty days of the OCC's
filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal
with the deferral appeals discussed above and to postpone oral arguments in
the
deferral appeal until after all briefs are filed in this most recent appeal
of
the rider recovery mechanism. On April 18, 2006, the Court denied both parts
of
the motion but on its own motion consolidated the OCC's appeal of the Ohio
Companies' case with a similar case of Dayton Power & Light Company and
stayed briefing on these appeals.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Ohio.
Pennsylvania
As
of March 31,
2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998
Restructuring Settlement (including the Phase 2 Proceedings) and the
FirstEnergy/GPU Merger Settlement Stipulation are $328 million and
$50 million, respectively. Penelec's $50 million is subject to the pending
resolution of taxable income issues associated with NUG trust fund proceeds.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for
deferral of transmission-related costs beginning January 1, 2005. The OCA,
OSBA,
OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
Association have all intervened in the case. As of March 31, 2006, the PPUC
had
taken no action on the request and neither company had yet implemented deferral
accounting for these costs. Met-Ed and Penelec sought to consolidate this
proceeding (and modified their request to provide deferral of 2006
transmission-related costs only) with the comprehensive rate filing they made
on
April 10, 2006 as described below. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Met-Ed and Penelec will implement deferral
accounting for these costs in the second quarter of 2006, which will include
$24
million and $4 million, respectively, representing the amounts that were
incurred in the first quarter of 2006 - the deferrals of such amounts will
be
reflected in the second quarter of 2006.
Met-Ed
and Penelec
purchase a portion of their PLR requirements from FES through a wholesale power
sales agreement. Under this 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 contracts with NUGs and other
unaffiliated suppliers. The FES 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.
The wholesale power sales agreement with FES could automatically be extended
for
each successive calendar year unless any party elects to cancel the agreement
by
November 1 of the preceding year. On November 1, 2005, FES and the other
parties thereto amended the agreement to provide FES the right in 2006 to
terminate the agreement at any time upon 60 days notice. On April 7, 2006,
the parties to the wholesale power sales agreement entered into a Tolling
Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
to exercise its right to terminate the wholesale power sales agreement effective
midnight December 31, 2006, because that agreement is not economically
sustainable to FES.
In
lieu of allowing
such termination to become effective as of December 31, 2006, the parties
agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales
agreement to provide as follows:
1. The
termination
provisions of the wholesale power sales agreement will be tolled for one year
until December 31, 2007, provided that during such tolling
period:
a. FES
will be
permitted to terminate the wholesale power sales agreement at any time with
sixty days written notice;
b. Met-Ed
and
Penelec will procure through arrangements other than the wholesale power sales
agreement beginning December 1, 2006 and ending December 31, 2007, approximately
33% of the amounts of capacity and energy necessary to satisfy their PLR
obligations for which Committed Resources (i.e., non-utility generation under
contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities,
purchased power contracts and distributed generation) have not been obtained;
and
c. FES
will not
be obligated to supply additional quantities of capacity and energy in the
event
that a supplier of Committed Resources defaults on its supply
agreement.
2. During
the tolling
period FES will not act as agent for Met-Ed or Penelec in procuring the services
under section 1.(b) above; and
3. The
pricing
provision of the wholesale power sales agreement shall remain unchanged provided
Met-Ed and Penelec comply with the provisions of the Tolling greement and any
applicable provision of the wholesale power sales agreement.
In
the event that
FES elects not to terminate the wholesale power sales agreement effective
midnight December 31, 2007, similar tolling agreements effective after
December 31, 2007 are expected to be considered by FES for subsequent years
if
Met-Ed and Penelec procure through arrangements other than the wholesale power
sales agreement approximately 64%, 83% and 95% of the additional amounts of
capacity and energy necessary to satisfy their PLR obligations for 2008, 2009
and 2010, respectively, for which Committed Resources have not been obtained
from the market.
The
wholesale power
sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
Penelec to satisfy the portion of their PLR obligations currently supplied
by
FES from unaffiliated suppliers at prevailing prices, which are likely to be
higher than the current price charged by FES under the current agreement and,
as
a result, Met-Ed’s and Penelec’s purchased power costs could materially
increase. If Met-Ed and Penelec were to replace the entire FES supply at current
market power prices without corresponding regulatory authorization to increase
their generation prices to customers, each company would likely incur a
significant increase in operating expenses and experience a material
deterioration in credit quality metrics. Under such a scenario, each company's
credit profile would no longer be expected to support an investment grade rating
for its fixed income securities. There can be no assurance, however, that if
FES
ultimately determines to terminate, or significantly modify the agreement,
timely regulatory relief will be granted by the PPUC pursuant to the April
10,
2006 comprehensive rate filing discussed below, or, to the extent granted,
adequate to mitigate such adverse consequences.
Met-Ed
and Penelec
made a comprehensive rate filing with the PPUC on April 10, 2006 that
addresses a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals is approved,
the
filing would increase annual revenues by $216 million and $157 million,
respectively. That filing includes, among other things, a request to charge
customers for an increasing amount of market priced power procured through
a
competitive bid process as the amount of supply provided under the existing
FES
agreement is phased out in accordance with the April 7, 2006 Tolling agreement
described above. Met-Ed
and Penelec
also requested approval of the January 12, 2005 petition for the deferral of
transmission-related costs discussed above, but only for those costs incurred
during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
of
annual transmission and related costs incurred on or after January 1, 2007,
plus the amortized portion of 2006 costs over a ten-year period, along with
applicable carrying charges, through an adjustable rider similar to that
implemented in Ohio.
Changes in the
recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
are
also included in the filing. The filing contemplates a reduction in distribution
rates for Met-Ed in the amount of $37 million annually and an increase in
distribution rates for Penelec in the amount of $20 million annually.
Although the companies have proposed an effective date of June 10, 2006, it
is expected that the PPUC will suspend the effective date for seven months
as
permitted under Pennsylvania law. Hearings are expected to be scheduled for
the
second half of 2006 and a PPUC decision is expected early in the first quarter
of 2007.
On
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for its
customers at set rates following the end of its transition period on
December 31, 2006. Penn recommended that the RFP process cover the period
January 1, 2007 through May 31, 2008. Hearings were held on
January 10, 2006 with main briefs filed on January 27, 2006 and reply
briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a
Recommended Decision to adopt Penn's RFP process with modifications. The PPUC
approved the Recommended Decision with additional modifications on
April 20, 2006. The approved plan is designed to provide customers with PLR
service for January 1, 2007 through May 31, 2008. Under Pennsylvania's
electric competition law, Penn is required to secure generation supply for
customers who do not choose alternative suppliers for their electricity.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Pennsylvania.
New
Jersey
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 NUGC rates and market sales
of NUG energy and capacity. As of March 31, 2006, the accumulated deferred
cost
balance totaled approximately $558 million. New Jersey law allows for
securitization of JCP&L's deferred balance upon application by JCP&L and
a determination by the NJBPU that the conditions of the New Jersey restructuring
legislation are met. On February 14, 2003, JCP&L filed for approval to
securitize the July 31, 2003 deferred balance. On December 2, 2005,
JCP&L filed a request for recovery of $165 million of actual
above-market NUG costs incurred from August 1, 2003 through
October 31, 2005 and forecasted above-market NUG costs for November and
December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the
financial advisor. Meetings with the NJBPU Staff and the DRA were held during
March and April and additional discovery conducted. The DRA filed comments
on
April 6, 2006, arguing that the proposed securitization does not produce
customer savings. JCP&L submitted reply comments on April 10, 2006. On
February 23, 2006, JCP&L filed updated data reflecting actual amounts
through December 31, 2005 of $154 million of cost incurred since July
31, 2003. The filing also includes a request for recovery of $49 million
for above-market NUG costs incurred prior to August 1, 2003, to the extent
those costs are not recoverable through securitization. On March 29, 2006,
a pre-hearing conference was held with the presiding ALJ. A schedule for the
proceeding was established including a discovery period and evidentiary hearings
scheduled for September 2006.
An
NJBPU Decision
and Order approving a Phase II Stipulation of Settlement and resolving the
Motion for Reconsideration of the Phase I Order was issued on May 31, 2005.
The
Phase II Settlement includes a performance standard pilot program with potential
penalties of up to 0.25% of equity return. The Order requires that JCP&L
file quarterly reliability reports (CAIDI and SAIFI information related to
the
performance pilot program) through December 2006 and updates to reliability
related project expenditures until all projects are completed. The first
quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly
report was submitted on November 22, 2005. The third quarterly report as of
December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005
there were no performance penalties issued by the NJBPU.
On August 1, 2005, the NJBPU established a proceeding to determine whether
additional ratepayer protections are required at the state level in light of
the
recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address
the issues was published in the NJ Register on December 19, 2005. The
proposal would prevent a holding company that owns a gas or electric public
utility from investing more than 25% of the combined assets of its utility
and
utility-related subsidiaries into businesses unrelated to the utility industry.
A public hearing was held February 7, 2006 and comments were submitted to
the NJBPU. The
NJBPU Staff
issued a draft proposal on March 31, 2006 addressing various issues
including access to books and records, ring-fencing, cross subsidization,
corporate governance and related matters. Comments and reply comments are due
by
May 22 and May 31, 2006, respectively. JCP&L is not able to predict the
outcome of this proceeding at this time.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in New Jersey.
FERC
Matters
On
November 18,
2004, the FERC issued an order eliminating the regional through and out rates
(RTOR) for transmission service between the MISO and PJM regions. The FERC
also
ordered the MISO, PJM and the transmission owners within the MISO and PJM to
submit compliance filings containing a mechanism - the Seams Elimination Cost
Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
period from load serving entities. The FERC issued orders in 2005 setting the
SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
involved in the FERC hearings concerning the calculation and imposition of
the
SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
Presiding Judge to issue an initial decision by August 11,
2006.
On
November 1, 2004,
ATSI filed with FERC a request to defer approximately $54 million of costs
to be incurred from 2004 through 2007 in connection with ATSI’s Vegetation
Management Enhancement Project (VMEP), which represents ATSI’s adoption of newly
identified industry “best practices” for vegetation management. On March 4,
2005, the FERC approved ATSI’s request to defer the VMEP costs (approximately
$29 million deferred as of March 31, 2006). On March 28, 2006 ATSI and MISO
filed with FERC a request to modify ATSI’s Attachment O formula rate to include
revenue requirements associated with recovery of deferred VMEP costs over a
five-year period. The requested effective date to begin recovery is June 1,
2006. Various parties have filed comments responsive to the March 28, 2006
submission. The FERC has not taken any action on the filing. The estimated
impact of the VMEP cost recovery is $13 million in revenues annually during
the five-year recovery period of June 1, 2006 to May 31,
2011.
On
January 24,
2006, ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O
formula rate to reverse revenue credits associated with termination of revenue
streams from transitional rates stemming from FERC’s elimination of through and
out rates. Revenues formerly collected under these rates were included in,
and
served to reduce, ATSI’s zonal transmission rate under the Attachment O formula.
Absent the requested correction, elimination of these revenue streams would
not
be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16,
2006, FERC approved without suspension the revenue credit correction, which
became effective April 1, 2006. One party sought rehearing of the FERC order.
The FERC has not yet issued a further order. The estimated impact of the
correction mechanism is approximately $40 million in revenues on an annualized
basis beginning June 1, 2006.
On
January 31,
2005, certain PJM transmission owners made three filings with the FERC pursuant
to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In
the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. In the second
filing, the settling transmission owners proposed a revised Schedule 12 to
the PJM tariff designed to harmonize the rate treatment of new and existing
transmission facilities. Interventions and protests were filed on
February 22, 2005. In the third filing, Baltimore Gas and Electric Company
and Pepco Holdings, Inc. requested a formula rate for transmission service
provided within their respective zones. On May 31, 2005, the FERC issued an
order on these cases. First, it set for hearing the existing rate design and
indicated that it will issue a final order within six months. American
Electric
Power Company, Inc. filed in opposition proposing to create a "postage stamp"
rate for high voltage transmission facilities across PJM.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to referral and hearing procedures. On
June 30, 2005, the settling PJM transmission owners filed a request for
rehearing of
the May 31,
2005
order. On
March 20, 2006 a settlement was filed with FERC in the formula rate
proceeding that generally accepts the companies' formula rate proposal. The
FERC
issued an order approving this settlement on April 19, 2006. If the FERC
accepts AEP's proposal, significant additional transmission revenues would
be
imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within
PJM.
On
November 1, 2005,
FES filed two power sales agreements for approval with the FERC. One power
sales
agreement provided for FES to provide the PLR requirements of the Ohio Companies
at a price equal to the retail generation rates approved by the PUCO for a
period of three years beginning January 1, 2006. The Ohio Companies will be
relieved of their obligation to obtain PLR power requirements from FES if the
Ohio competitive bid process results in a lower price for retail customers.
A
similar power sales agreement between FES and Penn permits Penn to obtain its
PLR power requirements from FES at a fixed price equal to the retail generation
price during 2006. The PPUC approved Penn's plan with modifications on April
20,
2006 to use an RFP process to obtain its power supply requirements after
2006.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio competitive bid process, and required
FES
to submit additional evidence in support of the reasonableness of the prices
charged in the power sales agreements. A pre-hearing conference was held on
January 18, 2006 to determine the hearing schedule in this case. FES
expects an initial decision to be issued in this case in late January 2007,
as a
result of an April 20, 2006 extension of the procedural schedule. The outcome
of
this proceeding cannot be predicted. FES has sought rehearing of the
December 29, 2005 order and the FERC granted rehearing for further
consideration on March 1, 2006.
Environmental
Matters
The
Companies accrue
environmental liabilities only when it is probable that they have an obligation
for such costs and can reasonably estimate 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.
On
December 1,
2005, FirstEnergy issued a comprehensive report to shareholders regarding air
emissions regulations and an assessment of future risks and mitigation efforts.
The report is available on FirstEnergy's web site at
www.firstenergycorp.com/environmental.
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 March 10, 2005, the EPA finalized CAIR covering a
total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania)
and
the District of Columbia based on proposed findings that air emissions from
28 eastern states and the District of Columbia significantly contribute to
non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS
in other states. CAIR provides each affected state until 2006 to develop
implementing regulations to achieve additional reductions of NOX
and SO2
emissions in two
phases (Phase I in 2009 for NOX,
2010 for
SO2
and Phase II in
2015 for both NOX
and SO2).
FirstEnergy's
Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
subject to caps on SO2
and
NOX
emissions, whereas
its New Jersey fossil-fired generation facilities will be subject to a cap
on
NOX
emissions only.
According to the EPA, SO2
emissions
will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the
rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2
emissions in
affected states to just 2.5 million tons annually. NOX
emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the
rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOX
cap of
1.3 million tons annually. The future cost of compliance with these
regulations may be substantial and will depend on 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 March 14, 2005, the EPA
finalized CAMR, which provides for a cap-and-trade program to reduce mercury
emissions from coal-fired power plants in two phases. Initially, mercury
emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit"
from implementation of SO2
and NOX
emission caps under
the EPA's CAIR program). Phase II of the mercury cap-and-trade program will
cap
nationwide mercury emissions from coal-fired power plants at 15 tons per
year by 2018. However, the final rules give states substantial discretion in
developing rules to implement these programs. In addition, both CAIR and CAMR
have been challenged in the United States Court of Appeals for the District
of
Columbia. FirstEnergy's future cost of compliance with these regulations may
be
substantial and will depend on how they are ultimately implemented by the states
in which FirstEnergy operates affected facilities.
The
model rules for
both CAIR and CAMR contemplate an input-based methodology to allocate allowances
to affected facilities. Under this approach, allowances would be allocated
based
on the amount of fuel consumed by the affected sources. FirstEnergy would prefer
an output-based generation-neutral methodology in which allowances are allocated
based on megawatts of power produced. Since this approach is based on output,
new and non-emitting generating facilities, including renewables and nuclear,
would be entitled to their proportionate share of the allowances. Consequently,
FirstEnergy would be disadvantaged if these model rules were implemented because
FirstEnergy's substantial reliance on non-emitting (largely nuclear) generation
is not recognized under the input-based allocation.
W.
H. Sammis
Plant
In
1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities alleging violations
of
the Clean Air Act based on operation and maintenance of 44 power plants,
including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
In addition, the DOJ filed eight civil complaints against various investor-owned
utilities, including 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. On March 18, 2005, OE and Penn announced that they had
reached a settlement with the EPA, the DOJ and three states (Connecticut, New
Jersey, and New York) that resolved all issues related to the W. H. Sammis
Plant
New Source Review litigation. This settlement agreement was approved by the
Court on July 11, 2005, and requires reductions of NOX
and SO2
emissions at the
W. H. Sammis Plant and other coal fired plants through the installation of
pollution control devices and provides for stipulated penalties for failure
to
install and operate such pollution controls in accordance with that agreement.
Consequently, if FirstEnergy fails to install such pollution control devices,
for any reason, including, but not limited to, the failure of any third-party
contractor to timely meet its delivery obligations for such devices, FirstEnergy
could be exposed to penalties under the settlement agreement. Capital
expenditures necessary to meet those requirements are currently estimated to
be
$1.5 billion (the primary portion of which is expected to be spent in the
2008 to 2011 time period). On August 26, 2005, FGCO entered into an
agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will
engineer, procure, and construct air quality control systems for the reduction
of sulfur dioxide emissions. The settlement agreement also requires OE and
Penn
to spend up to $25 million toward environmentally beneficial projects,
which include wind energy purchased power agreements over a 20-year term. OE
and
Penn agreed to pay a civil penalty of $8.5 million. Results for the first
quarter of 2005 included the penalties paid by OE and Penn of $7.8 million
and $0.7 million, respectively. OE and Penn also recognized liabilities in
the first quarter of 2005 of $9.2 million and $0.8 million,
respectively, for probable future cash contributions toward environmentally
beneficial projects.
Climate Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and
2012. The United States signed the Kyoto Protocol in 1998 but it failed to
receive the two-thirds vote of the United States Senate required for
ratification. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity - the
ratio of emissions to economic output - by 18% through 2012. The EPACT
established a Committee on Climate Change Technology to coordinate federal
climate change activities and promote the development and deployment of GHG
reducing technologies.
FirstEnergy
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
include low or non-CO2
emitting gas-fired
and nuclear generators.
Regulation
of
Hazardous 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 are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
March 31, 2006, based on estimates of the total costs of cleanup, the
Companies' proportionate responsibility for such costs and the financial ability
of other unaffiliated 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. Total liabilities of approximately $63 million have
been accrued through March 31, 2006.
See
Note 10(B)
to the
consolidated financial statements for further details and a complete discussion
of environmental matters.
Other
Legal Proceedings
Power
Outages
and Related Litigation
On
August 14,
2003, various states and parts of southern Canada experienced widespread power
outages. The outages affected approximately 1.4 million customers in
FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages concluded, among other things, that
the problems leading to the outages began in FirstEnergy’s Ohio service area.
Specifically,
the
final report concluded, among other things, that the initiation of the
August 14, 2003 power outages resulted from 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 real-time 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 14, 2003 power
outages and that it does not adequately address the underlying causes of the
outages. FirstEnergy remains convinced that the outages cannot be explained
by
events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and
were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. FirstEnergy’s implementation of these
recommendations in 2004 included completion of the Task Force recommendations
that were directed toward FirstEnergy. FirstEnergy also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability that were to be completed subsequent to 2004 and will continue
to
periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new or material upgrades to existing
equipment, and therefore FirstEnergy has not accrued a liability as of
March 31, 2006 for any expenditure in excess of those actually incurred
through that date. The FERC or other applicable government agencies and
reliability coordinators may, however, take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room operators
before determining the next steps, if any, in the proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class action
complaints. Of the four other pending PUCO complaint cases, three were filed
by
various insurance carriers either in their own name as subrogees or in the
name
of their insured. In each of the four cases, the carrier seeks reimbursement
from various FirstEnergy companies (and, in one case, from PJM, MISO and
American Electric Power Company, Inc. as well) for claims paid to insureds
for
damages allegedly arising as a result of the loss of power on August 14,
2003. The listed insureds in these cases, in many instances, are not customers
of any FirstEnergy company. The fourth case involves the claim of a non-customer
seeking reimbursement for losses incurred when its store was burglarized on
August 14, 2003. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of the
Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled
that
the U.S.-Canada Power System Outage Task Force Report was not admissible into
evidence; and gave the plaintiffs additional time to amend their complaints
to
otherwise comply with the PUCO’s underlying order.
The plaintiffs in
one case have since filed an amended complaint. The named FirstEnergy companies
have answered and also have filed a motion to dismiss the action, which is
pending. Also, most complainants, along with the FirstEnergy companies, filed
applications for rehearing with the PUCO over various rulings contained in
the
March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
the insurance company claimants, as insurers, to prosecute their claims in
their
name so long as they also identify the underlying insured entities and the
Ohio
utilities which provide their service. The PUCO denied all other motions for
rehearing. No estimate of potential liability is available for any of these
cases. In addition to these six cases, the Ohio Companies were named as
respondents in a regulatory proceeding that was initiated at the PUCO in
response to complaints alleging failure to provide reasonable and adequate
service stemming primarily from the August 14, 2003 power outages.
Following the PUCO's March 7, 2006 order, that action was voluntarily
dismissed by the claimants.
In
addition to the
above proceedings, FirstEnergy was named in a complaint filed in Michigan State
Court by an individual who is not a customer of any FirstEnergy company. A
responsive pleading to this matter has been filed. FirstEnergy was also named,
along with several other entities, in a complaint in New Jersey State Court.
The
allegations against FirstEnergy are based, in part, on an alleged failure to
protect the citizens of Jersey City from an electrical power outage. No
FirstEnergy entity serves any customers in Jersey City. A responsive pleading
has been filed. On April 28, 2006, the Court granted FirstEnergy's motion
to dismiss. It is uncertain whether the plaintiff will appeal. No estimate
of
potential liability has been undertaken in either of these matters.
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 the Companies. Although unable to predict the impact
of
these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
to have legal liability in connection with these proceedings, it could have
a
material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
Nuclear
Plant
Matters
On
January 20,
2006, FENOC announced that it has entered into a deferred prosecution agreement
with the U.S. Attorney’s Office for the Northern District of Ohio and the
Environmental Crimes Section of the Environment and Natural Resources Division
of the DOJ related to FENOC’s communications with the NRC during the fall of
2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power
Station. Under the agreement, which expires on December 31, 2006, the
United States acknowledged FENOC’s extensive corrective actions at Davis-Besse,
FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge
of continued cooperation in any related criminal and administrative
investigations and proceedings, FENOC’s acknowledgement of responsibility for
the behavior of its employees, and its agreement to pay a monetary penalty.
The
DOJ will refrain from seeking an indictment or otherwise initiating criminal
prosecution of FENOC for all conduct related to the statement of facts attached
to the deferred prosecution agreement, as long as FENOC remains in compliance
with the agreement, which FENOC fully intends to do. FENOC paid a monetary
penalty of $28 million (which is not deductible for income tax purposes)
which reduced First Energy's earnings by $0.09 per common share in the fourth
quarter of 2005.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty
related to the degradation of the Davis-Besse reactor vessel head issue
discussed above. FirstEnergy accrued $2 million for a potential fine prior
to 2005 and accrued the remaining liability for the proposed fine during the
first quarter of 2005. On September 14, 2005, FENOC filed its response to
the NOV with the NRC. FENOC accepted full responsibility for the past failure
to
properly implement its boric acid corrosion control and corrective action
programs. The NRC NOV indicated that the violations do not represent current
licensee performance. FirstEnergy paid the penalty in the third quarter of
2005.
On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
the Davis-Besse head degradation to reflect the deferred prosecution agreement
that FENOC had reached with the DOJ.
On
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take prompt
and corrective action. FENOC operates the Perry Nuclear Power Plant.
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the
NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix. By an inspection report dated January 18, 2006, the NRC closed one
of the White Findings (related to emergency preparedness) which led to the
multiple degraded cornerstones.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Plant and stated that
the
CAL would remain open until substantial improvement was demonstrated. The CAL
was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's
2005 annual assessment letter dated March 2, 2006 and associated meetings to
discuss the performance of Perry on March 14, 2006, the NRC again stated
that the Perry Plant continued to operate in a manner that "preserved public
health and safety." However, the NRC also stated that increased levels of
regulatory oversight would continue until sustained improvement in the
performance of the facility was realized. If performance does not improve,
the
NRC has a range of options under the Reactor Oversight Process, from increased
oversight to possible impact to the plant’s operating authority. Although
FirstEnergy is unable to predict the impact of the ultimate disposition of
this
matter, it could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
As
of
December 16, 2005, NGC acquired ownership of the nuclear generation assets
transferred from OE, CEI, TE and Penn with the exception of leasehold interests
of OE and TE in certain of the nuclear plants that are subject to sale and
leaseback arrangements with non-affiliates.
Other
Legal
Matters
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy’s normal business operations pending against FirstEnergy
and its subsidiaries. The other material items not otherwise discussed above
are
described below.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have
become the subject of a formal order of investigation. The SEC's formal order
of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
FirstEnergy received a subpoena asking for background documents and documents
related to the restatements and Davis-Besse issues. On December 30, 2004,
FirstEnergy received a subpoena asking for documents relating to issues raised
during the SEC's PUHCA examination. On August 24, 2005 additional
information was requested regarding Davis-Besse related disclosures, which
FirstEnergy has provided. FirstEnergy has cooperated fully with the informal
inquiry and will continue to do so with the formal investigation.
On
August 22,
2005, a class action complaint was filed against OE in Jefferson County, Ohio
Common Pleas Court, seeking compensatory and punitive damages to be determined
at trial based on claims of negligence and eight other tort counts alleging
damages from W.H. Sammis Plant air emissions. The two named plaintiffs are
also
seeking injunctive relief to eliminate harmful emissions and repair property
damage and the institution of a medical monitoring program for class members.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16 million to the bargaining unit employees. On February 6, 2006, the
federal court granted a Union motion to dismiss JCP&L's appeal of the award
as premature. JCP&L will file its appeal again in federal district court
once the damages associated with this case are identified at an individual
employee level. JCP&L recognized a liability for the potential
$16 million award in 2005.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of a newly
formed municipal electric utility. The complaint was filed on May 28, 2003,
and OE timely filed its response on June 30, 2003. In a related filing, the
Ohio Companies filed for approval with the PUCO a tariff that would specifically
allow the collection of transition charges from customers of municipal electric
utilities
formed after 1998.
An adverse ruling could negatively affect full recovery of transition charges
by
the utility. Hearings on the matter were held in August 2005. Initial briefs
from all parties were filed on September 22, 2005 and reply briefs were
filed on October 14, 2005. It is unknown when the PUCO will decide this
case.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters, it could
have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial
condition, results of operations and cash flows.
See
Note 10(C)
to the consolidated financial statements for further details and a complete
discussion of these and other legal proceedings.
NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or more
legally separate exchange transactions with the same counterparty should be
combined and considered as a single arrangement for purposes of applying
APB 29, when the transactions were entered into "in contemplation" of one
another. If two transactions are combined and considered a single arrangement,
the EITF reached a consensus that an exchange of inventory should be accounted
for at fair value. Although electric power is not capable of being held in
inventory, there is no substantive conceptual distinction between exchanges
involving power and other storable inventory. Therefore, FirstEnergy will adopt
this EITF effective for new arrangements entered into, or modifications or
renewals of existing arrangements, in interim or annual periods beginning after
March 15, 2006. This EITF issue will not have a material impact on
FirstEnergy's financial results.
SFAS
155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
Statements No. 133 and 140”
In
February 2006,
the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative
Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.”
This Statement permits fair value remeasurement for any hybrid financial
instrument that contains an embedded derivative that otherwise would require
bifurcation, clarifies which interest-only strips and principal-only strips
are
not subject to the requirements of SFAS 133, establishes a requirement to
evaluate interests in securitized financial assets to identify interests that
are freestanding derivatives or that are hybrid financial instruments that
contain an embedded derivative requiring bifurcation, clarifies that
concentrations of credit risk in the form of subordination are not embedded
derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
special-purpose entity from holding a derivative financial instrument that
pertains to a beneficial interest other than another derivative instrument.
This
Statement is effective for all financial instruments acquired or issued
beginning January 1, 2007. FirstEnergy is currently evaluating the impact
of this Statement on its financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF INCOME
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
$
|
586,203
|
|
$
|
726,358
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,951
|
|
|
11,916
|
|
|
Purchased
power
|
|
272,386
|
|
|
246,590
|
|
|
Nuclear
operating costs
|
|
41,084
|
|
|
95,653
|
|
|
Other
operating costs
|
|
90,810
|
|
|
83,179
|
|
|
Provision
for
depreciation
|
|
18,016
|
|
|
26,052
|
|
|
Amortization
of regulatory assets
|
|
53,861
|
|
|
111,771
|
|
|
Deferral
of
new regulatory assets
|
|
(25,606)
|
|
|
(24,795
|
) |
|
General
taxes
|
|
45,895
|
|
|
48,078
|
|
|
Income
taxes
|
|
30,550
|
|
|
54,972
|
|
|
|
Total
operating expenses and taxes
|
|
529,947
|
|
|
653,416
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
56,256
|
|
|
72,942
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
25,470
|
|
|
423
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
13,082
|
|
|
15,609
|
|
|
Allowance
for
borrowed funds used during construction and capitalized
interest
|
|
(491
|
)
|
|
(2,235
|
) |
|
Other
interest
expense
|
|
5,149
|
|
|
2,594
|
|
|
Subsidiary's
preferred stock dividend requirements
|
|
156
|
|
|
640
|
|
|
|
Net
interest
charges
|
|
17,896
|
|
|
16,608
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
63,830
|
|
|
56,757
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
659
|
|
|
659
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
$
|
63,171
|
|
$
|
56,098
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
$
|
63,830
|
|
$
|
56,757
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
5,735
|
|
|
(2,717
|
) |
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
2,069
|
|
|
(1,124
|
) |
|
|
Other
comprehensive income (loss), net of tax
|
|
3,666
|
|
|
(1,593
|
) |
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
$
|
67,496
|
|
$
|
55,164
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Ohio Edison
Company are an integral part of these statements.
|
|
OHIO
EDISON COMPANY
|
|
CONSOLIDATED
BALANCE SHEETS
|
(Unaudited)
|
|
|
March
31,
|
|
|
December
31,
|
|
|
2006
|
|
|
2005
|
|
|
(In
Thousands)
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
In
service
|
$
|
2,552,488
|
|
$
|
2,526,851
|
|
Less
-
Accumulated provision for depreciation
|
|
996,292
|
|
|
984,463
|
|
|
|
|
|
|
1,556,196
|
|
|
1,542,388
|
|
Construction
work in progress
|
|
56,728
|
|
|
58,785
|
|
|
|
|
|
|
1,612,924
|
|
|
1,601,173
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
Investment
in
lease obligation bonds
|
|
325,519
|
|
|
325,729
|
|
Nuclear
plant
decommissioning trusts
|
|
109,497
|
|
|
103,854
|
|
Long-term
notes receivable from associated companies
|
|
1,758,377
|
|
|
1,758,776
|
|
Other
|
|
|
43,491
|
|
|
44,210
|
|
|
|
|
|
|
2,236,884
|
|
|
2,232,569
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
1,048
|
|
|
929
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,136,000 and $7,619,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
251,937
|
|
|
290,887
|
|
|
Associated
companies
|
|
104,839
|
|
|
187,072
|
|
|
Other
(less
accumulated provisions of $23,000 and $4,000,
respectively,
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
20,239
|
|
|
15,327
|
|
Notes
receivable from associated companies
|
|
582,252
|
|
|
536,629
|
|
Prepayments
and other
|
|
27,017
|
|
|
93,129
|
|
|
|
|
|
|
987,332
|
|
|
1,123,973
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
Regulatory
assets
|
|
757,164
|
|
|
774,983
|
|
Prepaid
pension costs
|
|
226,314
|
|
|
224,813
|
|
Property
taxes
|
|
52,897
|
|
|
52,875
|
|
Unamortized
sale and leaseback costs
|
|
53,888
|
|
|
55,139
|
|
Other
|
|
|
29,013
|
|
|
31,752
|
|
|
|
|
|
|
1,119,276
|
|
|
1,139,562
|
|
|
|
|
|
$
|
5,956,416
|
|
$
|
6,097,277
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares -
100
shares
outstanding
|
$
|
2,297,289
|
|
$
|
2,297,253
|
|
|
Accumulated
other comprehensive income
|
|
7,760
|
|
|
4,094
|
|
|
Retained
earnings
|
|
229,015
|
|
|
200,844
|
|
|
|
Total
common
stockholder's equity
|
|
2,534,064
|
|
|
2,502,191
|
|
Preferred
stock not subject to mandatory redemption
|
|
60,965
|
|
|
60,965
|
|
Preferred
stock of consolidated subsidiary not subject to mandatory
redemption
|
|
14,105
|
|
|
14,105
|
|
Long-term
debt
and other long-term obligations
|
|
931,507
|
|
|
1,019,642
|
|
|
|
|
|
|
3,540,641
|
|
|
3,596,903
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
309,445
|
|
|
280,255
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
-
|
|
|
57,715
|
|
|
Other
|
|
22,584
|
|
|
143,585
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
181,663
|
|
|
172,511
|
|
|
Other
|
|
10,123
|
|
|
9,607
|
|
Accrued
taxes
|
|
191,375
|
|
|
163,870
|
|
Accrued
interest
|
|
12,054
|
|
|
8,333
|
|
Other
|
|
|
95,273
|
|
|
61,726
|
|
|
|
|
|
|
822,517
|
|
|
897,602
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
764,337
|
|
|
769,031
|
|
Accumulated
deferred investment tax credits
|
|
23,194
|
|
|
24,081
|
|
Asset
retirement obligation
|
|
84,282
|
|
|
82,527
|
|
Retirement
benefits
|
|
292,965
|
|
|
291,051
|
|
Deferred
revenues - electric service programs
|
|
113,930
|
|
|
121,693
|
|
Other
|
|
|
314,550
|
|
|
314,389
|
|
|
|
|
|
|
1,593,258
|
|
|
1,602,772
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$
|
5,956,416
|
|
$
|
6,097,277
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Ohio
Edison
Company. are an integral part of these balance
sheets. |
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
|
|
March
31,
|
|
|
|
|
|
|
|
Restated
2006
|
|
|
2005
|
|
|
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
income
|
|
|
$
|
63,830
|
|
$
|
56,757
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
18,016
|
|
|
26,052
|
|
|
Amortization
of regulatory assets
|
|
|
53,861
|
|
|
111,771
|
|
|
Deferral
of
new regulatory assets
|
|
|
(25,606
|
) |
|
(24,795
|
) |
|
Nuclear
fuel
and lease amortization
|
|
|
532
|
|
|
9,170
|
|
|
Deferred
purchased power costs
|
|
|
(10,634
|
) |
|
-
|
|
|
Amortization
of lease costs
|
|
|
32,934
|
|
|
33,030
|
|
|
Deferred
income taxes and investment tax credits, net
|
(3,945
|
) |
|
(24,627
|
) |
|
Accrued
compensation and retirement benefits
|
|
(1,494
|
) |
|
(1,973
|
) |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
|
116,271
|
|
|
86,123
|
|
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(15,834
|
) |
|
|
Prepayments
and other current assets
|
|
(12,136
|
) |
|
(12,877
|
) |
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
9,668
|
|
|
(39,854
|
) |
|
|
Accrued
taxes
|
|
|
27,505
|
|
|
44,448
|
|
|
|
Accrued
interest
|
|
|
3,721
|
|
|
6,993
|
|
|
Electric
service prepayment programs
|
|
|
(7,763
|
) |
|
-
|
|
|
Other
|
|
|
|
3,922
|
|
|
13,297
|
|
|
|
Net
cash
provided from operating activities
|
|
268,682
|
|
|
267,681
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
31,182
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
|
(59,506
|
) |
|
(15,787
|
) |
|
Short-term
borrowings, net
|
|
|
(178,716
|
) |
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
(35,000
|
) |
|
(47,000
|
) |
|
Preferred
stock
|
|
|
|
(659
|
) |
|
(659
|
) |
|
|
Net
cash
provided from financing activities
|
|
(273,881
|
) |
|
(32,264
|
) |
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
|
(28,793
|
) |
|
(79,783
|
) |
Proceeds
from
nuclear decommissioning trust fund sales
|
|
19,054
|
|
|
68,400
|
|
Investments
in
nuclear decommissioning trust funds
|
|
(19,054
|
) |
|
(76,285
|
) |
Loans
to
associated companies, net
|
|
|
|
(45,224
|
) |
|
(154,038
|
) |
Cash
investments
|
|
|
|
78,248
|
|
|
-
|
|
Other
|
|
|
|
|
|
1,087
|
|
|
6,263
|
|
|
|
Net
cash
provided from investing activities
|
|
5,318
|
|
|
(235,443
|
) |
|
|
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
119
|
|
|
(26
|
) |
Cash
and cash
equivalents at beginning of period
|
|
|
929
|
|
|
1,230
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
1,048
|
|
$
|
1,204
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Ohio Edison
Company are an integral part of these statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of Ohio
Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of Ohio Edison Company and its
subsidiaries as of March 31, 2006, and the related consolidated statements
of
income and comprehensive income and cash flows for each of the three-month
periods ended March 31, 2006 and 2005. 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
described in the
section entitled "Restatement of the Consolidated Statements of Cash Flows"
included in Note 1 to the consolidated interim financial statements, the Company
has restated its previously issued consolidated interim financial statements
for
the quarter ended March 31, 2006.
We
have previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2005, and the related consolidated statements of income, capitalization,
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 and conditional asset retirement obligations
as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
consolidated financial statements] dated February 27, 2006, 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, 2005, is fairly stated in all material respects in relation to
the
consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May
8, 2006,
except as to Note 1, which is as of October 31,
2006
|
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. The OE Companies also provide generation
services to those customers electing to retain the OE Companies as their power
supplier. Power supply requirements of the OE Companies are provided by FES
-
an affiliated
company.
FirstEnergy
Intra-System Generation Asset Transfers
On
May 13,
2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
agreements implementing a series of intra-system generation asset transfers
that
were completed in the fourth quarter of 2005. The asset transfers resulted
in
the respective undivided ownership interests of the Ohio Companies and Penn
in
FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
FGCO, respectively. The generating plant interests transferred did not include
OE's leasehold interests in certain of the plants that are currently subject
to
sale and leaseback arrangements with non-affiliates.
On
October 24,
2005, the OE Companies completed the intra-system transfer of non-nuclear
generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master
Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
the non-nuclear generation assets that it now owns. The asset transfers were
consummated pursuant to FGCO's purchase option under the Master Facility
Lease.
On
December 16,
2005, the OE Companies completed the intra-system transfer of their ownership
interests in the nuclear generation assets to NGC through an asset spin-off
in
the form of a dividend. FENOC continues to operate and maintain the nuclear
generation assets.
These
transactions
were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans
that were approved by the PUCO and the PPUC, respectively, under applicable
Ohio
and Pennsylvania electric utility restructuring legislation. Consistent with
the
restructuring plans, generation assets that had been owned by the Ohio Companies
and Penn were required to be separated from the regulated delivery business
of
those companies through transfer to a separate corporate entity. The
transactions essentially completed the divestitures contemplated by the
restructuring plans by transferring the ownership interests to NGC and FGCO
without impacting the operation of the plants.
The
transfers will
affect the OE Companies' near-term results with reductions in both revenues
and
expenses. Revenues are reduced due to the termination of certain arrangements
with FES, under which the OE Companies previously sold their nuclear-generated
KWH to FES and leased their non-nuclear generation assets to FGCO, a subsidiary
of FES. Their expenses are lower due to the nuclear fuel and operating costs
assumed by NGC as well as depreciation and property tax expenses assumed by
FGCO
and NGC related to the transferred generating assets. With respect to OE's
retained leasehold interests in the Perry Nuclear Power Plant and Beaver Valley
Power Station Unit 2. OE has continued the nuclear-generated KWH sales
arrangement with FES for the associated output and continues to be obligated
on
the applicable portion of expenses related to those interests. In addition,
the
OE Companies receive interest income on associated company notes receivable
from
the transfer of their generation net assets. FES will continue to provide the
OE
Companies’ PLR requirements under revised purchased power arrangements for the
three-year period beginning January 1, 2006 (see Regulatory
Matters).
The
effects on the
OE Companies' results of operations in the first quarter of 2006 compared to
the
first quarter of 2005 from the generation asset transfers (also reflecting
OE's
retained leasehold interests discussed above) are summarized in the following
table:
Intra-System
Generation Asset Transfers -
|
First
Quarter 2006 vs First Quarter 2005 Income Statement
Effects
|
Increase
(Decrease)
|
|
(In
millions)
|
|
|
Operating
Revenues:
|
|
|
|
|
Non-nuclear
generating units rent
|
|
$
|
(45
|
)
|
(a)
|
|
Nuclear
generated KWH sales
|
|
|
(64
|
)
|
(b)
|
|
Total
-
Operating Revenues Effect
|
|
|
(109
|
)
|
|
|
Operating
Expenses and Taxes:
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
|
|
(9
|
)
|
(c)
|
|
Nuclear
operating costs
|
|
|
(46
|
)
|
(c)
|
|
Provision
for
depreciation
|
|
|
(17
|
)
|
(d)
|
|
General
taxes
|
|
|
(3
|
)
|
(e)
|
|
Income
taxes
|
|
|
(15
|
)
|
(i)
|
|
Total
-
Operating Expenses and Taxes Effect
|
|
|
(90
|
)
|
|
|
Operating
Income Effect
|
|
|
(19
|
)
|
|
|
Other
Income:
|
|
|
|
|
|
|
Interest
income from notes receivable
|
|
|
15
|
|
(f)
|
|
Nuclear
decommissioning trust earnings
|
|
|
(2
|
)
|
(g)
|
|
Income
taxes
|
|
|
(5
|
)
|
(i)
|
|
Total
- Other
Income Effect
|
|
|
8
|
|
|
|
Net
Interest
Charges:
|
|
|
|
|
|
|
Allowance
for
funds used during construction
|
|
|
(2
|
)
|
(h)
|
|
Total
- Net
Interest Charges Effect
|
|
|
2
|
|
|
|
Net
Income
Effect
|
|
$
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
(a)
Elimination of non-nuclear generation assets lease to
FGCO.
|
(b)
Reduction
of nuclear generated wholesale KWH sales to FES.
|
(c)
Reduction
of nuclear fuel and operating costs.
|
(d)
Reduction
of depreciation expense and asset retirement obligation accretion
related
to generation
assets.
|
(e)
Reduction
of property tax expense on generation assets.
|
(f)
Interest
income on associated company notes receivable from the
|
transfer
of
generation net assets.
|
(g)
Reduction
of earnings on nuclear decommissioning trusts.
|
(h)
Reduction
of allowance for borrowed funds used during construction on nuclear
capital expenditures.
|
(i)
Income tax
effect of the above adjustments.
|
Restatement
of Consolidated Statement of Cash Flows
As
further discussed
in Note 1 to the Consolidated Financial Statements, OE is restating its
Consolidated Statement of Cash Flows for the three months ended March 31,
2006.
This corrects a misclassification of a $78 million cash receipt from the
liquidation of cash investments (restricted cash related to the 2005 generation
asset transfers) in the first quarter of 2006. The cash receipt was previously
reported in cash flows from operating activities and should have been reported
in cash flows from investing activities. This correction resulted in a
$78
million decrease in the previously reported cash flows from operating activities
and a corresponding increase in cash flows from investing activities in
its
consolidated statements of cash flows for the three months ended March
31, 2006.
This resulted in revisions in the previously reported Management’s Discussion
and Analysis of Results of Operations only to Capital Resources and Liquidity
under the Cash Flows From Operating Activities and Cash Flows From Investing
Activities sections. The correction does not change OE’s previously reported
consolidated statements of income and comprehensive income for the three
months
ended March 31, 2006 or its consolidated balance sheet as of March 31,
2006.
Results
of Operations
Earnings
on common
stock in the first quarter of 2006 increased to $63 million from
$56 million in the first quarter of 2005. The increase in earnings in 2006
primarily resulted from reduced operating expenses and taxes and increased
other
income, partially offset by lower operating revenues and increased net interest
charges principally from the asset transfer effects shown in the table above.
Operating
Revenues
Operating
revenues
decreased by $140 million or 19.3% in the first quarter of 2006 compared with
the same period in 2005, primarily due to the generation asset transfer impact
summarized in the table above. Excluding the effects of the asset transfer,
operating revenues decreased $31 million, primarily due to decreases of
$59 million and $98 million in wholesale sales and distribution
revenues, respectively, partially offset by increases in retail generation
revenues of $108 million and reduced customer shopping incentives of
$18 million.
The
lower wholesale
revenues reflected the termination of a non-affiliated wholesale sales agreement
and the cessation of the MSG sales arrangements under OE’s transition plan in
December 2005. OE had been required to provide the MSG to non-affiliated
alternative suppliers.
Increased
retail
generation revenues in all customer sectors (residential - $43 million;
commercial - $32 million; and industrial - $33 million) reflected the
impact of higher KWH sales and higher unit prices. The increase in generation
KWH sales primarily resulted from decreased customer shopping, as the percentage
of generation services provided by alternative suppliers to total sales
delivered in OE's service area decreased by the following percentages:
residential - 8.8%; commercial - 11.0%; and industrial - 9.3%. The decreased
shopping resulted from alternative energy suppliers terminating their supply
arrangements with OE’s shopping customers in the fourth quarter of 2005. Higher
unit prices reflected the Rate Stabilization Charge and fuel recovery rider
that
became effective in January 2006 under the RCP.
Revenues
from
distribution throughput decreased $98 million in the first quarter of 2006
compared with the same period in 2006. The decrease in all customer sectors
(residential - $40 million; commercial - $32 million; and industrial -
$26 million) primarily reflected the impact of lower composite prices and
reduced KWH deliveries. The lower unit prices reflected the completion of the
generation-related transition cost recovery under OE’s and Penn’s respective
rate restructuring plans in 2005, partially offset by the recovery of MISO
costs
beginning in 2006 (see Outlook -- Regulatory Matters). Lower distribution KWH
deliveries to residential and commercial customers reflected the impact of
milder weather conditions in the first quarter of 2006, compared to the same
period of 2005.
Under
the Ohio
transition plan, OE had provided incentives to customers to encourage switching
to alternative energy providers, which reduced OE’s revenues by $18 million in
the first quarter of 2005. These revenue reductions, which were deferred for
future recovery and did not affect current period earnings, ceased in 2006.
The
deferred shopping incentives (Extended RTC) are now being recovered under the
RCP (see Regulatory Matters below.)
Changes
in electric
generation sales and distribution deliveries in the first quarter of 2006 from
the same quarter of 2005 are summarized in the following table:
Changes
in KWH Sales
|
|
|
|
Increase
(Decrease)
|
|
|
|
Electric
Generation:
|
|
|
|
Retail
|
|
|
11.3
|
%
|
Wholesale - Non-Associated
|
|
|
(95.6
|
)%
|
Wholesale
-
Associated (FES)*
|
|
|
(75.7
|
)%
|
Total
Electric Generation Sales
|
|
|
(28.0
|
)%
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
Residential
|
|
|
(1.8
|
)%
|
Commercial
|
|
|
(1.0
|
)%
|
Industrial
|
|
|
(1.7
|
)%
|
Total
Distribution Deliveries
|
|
|
(1.5
|
)%
|
|
|
|
|
|
*Change
reflects impact of generation asset transfers.
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes decreased by $123 million in the first quarter of 2006 from
the first quarter of 2005 principally due to the effects of the generation
asset
transfer shown in the table above. Excluding the asset transfer effects, the
following table presents changes from the prior year by expense
category.
Operating
Expenses and Taxes - Changes
|
|
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
26
|
|
Nuclear
operating costs
|
|
|
(8
|
)
|
Other
operating costs
|
|
|
7
|
|
Provision
for
depreciation
|
|
|
9
|
|
Amortization
of regulatory assets
|
|
|
(58
|
)
|
Deferral
of
new regulatory assets
|
|
|
(1
|
)
|
General
taxes
|
|
|
1
|
|
Income
taxes
|
|
|
(10
|
)
|
Total
operating expenses and taxes
|
|
$
|
(34
|
)
|
Increased
purchased
power costs in the first quarter of 2006 reflected higher unit prices associated
with the new power supply agreement with FES, partially offset by a decrease
in
KWH purchased to meet the lower net generation sales requirements, and RCP
fuel
deferrals of $11 million. Under the RCP that was effective January 1, 2006,
OE can defer increased fuel costs (i.e., in excess of 2002 baseline amounts)
above the amount collected through the fuel recovery mechanism. Excluding the
effects of the generation asset transfers, the lower nuclear operating costs
for
OE’s nuclear leasehold interests were primarily due to the absence in 2006 of
the Perry Nuclear Power Plant scheduled refueling outage (including an unplanned
extension) in the first quarter of 2005. The increase in other operating costs
was primarily from increased transmission expenses related to MISO Day 2
operations that began on April 1, 2005.
Excluding
the
effects of the generation asset transfers, higher depreciation expense in the
first quarter of 2006 compared with the same quarter of 2005 reflects capital
additions subsequent to the first quarter of 2005. Lower amortization of
regulatory assets was due to the completion of the generation-related transition
cost amortization under OE's and Penn's respective transition plans, partially
offset by the amortization of deferred MISO costs being recovered in 2006.
The
higher deferrals of new regulatory assets primarily resulted from the deferral
of distribution costs and related interest ($19 million) under the RCP,
partially offset by the decrease in shopping incentive deferrals
($18 million) which ceased in 2006 under the Ohio transition plan. The
deferral of interest on the unamortized shopping incentive balances will
continue under the RCP.
Other
Income
Other
income
increased $25 million in the first quarter of 2006 compared with the same
quarter of 2005, partially due to the effects of the asset transfer. Excluding
the asset transfer effects, the $17 million increase is primarily due to the
absence in 2006 of the 2005 accruals of an $8.5 million civil penalty payable
to
the DOJ and $10 million for environmental projects in connection with the
Sammis New Source Review settlement (see Outlook -
Environmental
Matters).
Net
Interest
Charges
Net
interest charges
increased $1 million in the first quarter of 2006 compared to the same period
of
2005 primarily due to the effects of the generation asset transfer. Excluding
the asset transfer, interest charges continued to trend lower, decreasing by
$1
million in the first quarter of 2006 compared with the same quarter of
2005.
Capital
Resources and Liquidity
OE’s
cash
requirements in 2006 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions are expected to be
met
with cash from operations and short-term credit arrangements. Available
borrowing capacity under credit facilities will be used to manage working
capital requirements.
In
connection with a
plan to realign its capital structure, OE may also issue up to $600 million
of
long-term debt in 2006 with proceeds expected to fund a return of equity capital
to FirstEnergy.
Changes
in Cash
Position
OE's
cash and cash
equivalents were approximately $1 million as of March 31, 2006 and
December 31, 2005.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities during the first quarter of 2006, (as restated) compared
with the first quarter of 2005, were as follows:
|
|
Three
Months Ended March 31,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings
(1)
|
|
$
|
120
|
|
$
|
185
|
|
Working
capital and other
|
|
|
149
|
|
|
83
|
|
Net
cash
provided from operating activities
|
|
$
|
269
|
|
$
|
268
|
|
(1) Cash
earnings are a
non-GAAP measure (see reconciliation below).
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. OE believes that cash earnings are a useful financial measure because
it
provides investors and management with an additional means of evaluating its
cash-based operating performance. The following table reconciles cash earnings
with net income:
|
|
Three
Months Ended March 31,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
Income
(GAAP)
|
|
$
|
64
|
|
$
|
57
|
|
Non-Cash
Charges (Credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
18
|
|
|
26
|
|
Amortization
of regulatory assets
|
|
|
54
|
|
|
112
|
|
Deferral
of
new regulatory assets
|
|
|
(26
|
)
|
|
(25
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
1
|
|
|
9
|
|
Amortization
of electric service obligation
|
|
|
(8
|
)
|
|
-
|
|
Amortization
of lease costs
|
|
|
33
|
|
|
33
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(4
|
)
|
|
(25
|
)
|
Deferred
purchased power costs
|
|
|
(11
|
)
|
|
-
|
|
Accrued
compensation and retirement benefits
|
|
|
(1
|
)
|
|
(2
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
120
|
|
$
|
185
|
|
Net
cash provided
from operating activities increased $1 million in the first quarter of 2006,
compared with the first quarter of 2005, due to a $66 million increase from
changes in working capital, partially offset by a $65 million decrease in
cash earnings as described above under “Results from Operations.” The increase
in working capital primarily reflects changes in the settlement of accounts
payable and receivables of $80 million partially offset by changes in
accrued taxes of $17 million.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities increased to $274 million in the first quarter of 2006
from
$32 million in the first quarter of 2005. The increase primarily reflected
repayments of short-term borrowings to associated companies, partially offset
by
a $12 million decrease in common stock dividend payments to FirstEnergy.
OE
had approximately
$583 million of cash and temporary cash investments (which include
short-term notes receivable from associated companies) and $23 million of
short-term indebtedness as of March 31, 2006. OE has authorization from the
PUCO to incur short-term debt of up to $500 million, which is expected to
come from the bank facility and the utility money pool described below. Penn
has
authorization from the SEC, continued by FERC rules adopted as a result of
EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of
$43 million as of March 31, 2006, and will have access to the bank
facility and the utility money pool.
OES
Capital is a
wholly owned subsidiary of OE whose borrowings are secured by customer accounts
receivable purchased from OE. OES Capital can borrow up to $170 million
under a receivables financing arrangement. As a separate legal entity with
separate creditors, OES Capital would have to satisfy its obligations to
creditors before any of its remaining assets could be made available to OE.
As
of March 31, 2006, the facility was not drawn.
Penn
Power Funding
LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
company whose borrowings are secured by customer accounts receivable purchased
from Penn. Penn Funding can borrow up to the full amount of $25 million
available as of March 31, 2006 under a receivables financing arrangement
which expires June 29,
2006.
As a separate legal entity with separate creditors, Penn Funding would have
to
satisfy its obligations to creditors before any of its remaining assets could
be
made available to Penn. As
of March 31,
2006, the facility was drawn for $19 million.
As
of March 31,
2006, OE and Penn had the aggregate capability to issue approximately
$502 million of additional FMB on the basis of property additions and
retired bonds under the terms of their respective mortgage indentures. The
issuance of FMB by OE is also subject to provisions of its senior note indenture
generally limiting the incurrence of additional secured debt, subject to certain
exceptions that would permit, among other things, the issuance of secured debt
(including FMB) (i) supporting pollution control notes or similar obligations,
or (ii) as an extension, renewal or replacement of previously outstanding
secured debt. In addition, OE is permitted under the indenture to incur
additional secured debt not otherwise permitted by a specified exception of
up
to $644 million as of March 31, 2006. Based upon applicable earnings
coverage tests in their respective charters, OE and Penn could issue a total
of
$3.1 billion of preferred stock (assuming no additional debt was issued) as
of March 31, 2006.
As
of April 26,
2006, a shelf registration statement filed by OE became effective and provides,
together with previously effective OE registration statements, $1 billion of
capacity to support future issuances of debt securities by OE.
FirstEnergy,
OE,
Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have
entered into a syndicated $2 billion five-year revolving credit facility
with a syndicate of banks that expires in June 2010. Borrowings under the
facility are available to each Borrower separately and mature on the earlier
of
364 days from the date of borrowing or the commitment termination date, as
the
same may be extended. OE's borrowing limit under the facility is
$500 million and Penn’s is $50 million, subject in each case to
applicable regulatory approvals.
Under
the revolving
credit facility, borrowers may request the issuance of letters of credit
expiring up to one year from the date of issuance. The stated amount of
outstanding letters of credit will count against total commitments available
under the facility and against the applicable borrower’s borrowing sub-limit.
Total unused borrowing capability under existing credit facilities and accounts
receivable financing facilities totaled $726 million as of March 31,
2006.
The
revolving credit
facility contains financial covenants requiring each borrower to maintain a
consolidated debt to total capitalization ratio of no more than 65%. As of
March
31, 2006, debt to total capitalization as defined under the revolving credit
facility was 33% for OE and 35% for Penn.
The
facility does
not contain any provisions that either restrict the ability of OE and Penn
to
borrow or accelerate repayment of outstanding advances as a result of any change
in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of
funds borrowed under the facility is related to OE’s and Penn’s credit
ratings.
OE
and Penn have the
ability to borrow from their regulated affiliates and FirstEnergy to meet their
short-term working capital requirements. FESC administers this money pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
receiving a loan under the money pool agreements must repay the principal
amount, together with accrued interest, within 364 days of borrowing the funds.
The rate of interest is the same for each company receiving a loan from the
pool
and is based on the average cost of funds available through the pool. The
average interest rate for borrowings in the first quarter of 2006 was
4.58%.
OE’s access to the capital markets and the costs of financing are influenced by
the ratings of its securities. The ratings outlook from S&P on all
securities is stable. The ratings outlook from Moody's and Fitch on all
securities is positive.
In April 2006, pollution control notes that were formerly obligations of OE
and
Penn were refinanced and became obligations of FGCO and NGC. The
proceeds from
the refinancings were used to repay a portion of their associated company notes
payable to Penn and OE. With those repayments, OE redeemed $74.8 million
and Penn redeemed $6.95 million of pollution control notes having variable
interest rates.
Cash
Flows From
Investing Activities
Net
cash provided
from investing activities totaled $5 million (as restated) in the first quarter
of 2006 compared to net cash of $235 million used in investing activities
in the first quarter of 2005. The change resulted primarily from a $109 million
decrease in loans to associated companies, $78 million from the liquidation
of a
temporary investment and a $51 million decrease in property additions,
which reflects the impact of the generation asset transfers.
During
the remaining
three quarters of 2006, capital requirements for property additions and capital
leases are expected to be approximately $93 million. OE has additional
requirements of approximately $4 million to meet requirements for maturing
long-term debt during the remainder of 2006. These cash requirements are
expected to be satisfied from a combination of internal cash, funds raised
in
the long-term debt capital markets and short-term credit arrangements.
OE’s
capital spending for the period 2006-2010 is expected to be about
$638 million, of which approximately $122 million applies to 2006.
Off-Balance
Sheet Arrangements
Obligations
not
included on OE’s Consolidated Balance Sheets primarily consist of sale and
leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The
present value of these operating lease commitments, net of trust investments,
was $666 million as of March 31, 2006.
Equity
Price Risk
Included
in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $71 million and $67 million
as of
March 31, 2006 and December 31, 2005, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in a $7 million
reduction in fair value as of March 31, 2006. Changes in the fair value of
these investments are recorded in OCI unless recognized as a result of a sale
or
recognized as regulatory assets or liabilities.
Outlook
The
electric
industry continues to transition to a more competitive environment and all
of
the OE Companies’ customers can select alternative energy suppliers. The OE
Companies continue to deliver power to residential homes and businesses through
their 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.
Regulatory
Matters
Regulatory
assets
are costs which have been authorized by the PUCO, the PPUC and the FERC for
recovery from customers in future periods or for which authorization is
probable. Without the probability of such authorization, costs currently
recorded as regulatory assets would have been charged to income as incurred.
All
regulatory assets are expected to be recovered under the provisions of the
OE
Companies’ transition plans and rate restructuring plans. OE‘s regulatory assets
were $757 million and $775 million as of March 31, 2006 and
December 31, 2005, respectively. Penn had net regulatory liabilities of
$64 million and $59 million as of March 31, 2006 and
December 31, 2005, respectively, which are included in Other Noncurrent
Liabilities on the Consolidated Balance Sheets as of March 31, 2006 and
December 31, 2005.
On
October 21, 2003
the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the
Ohio
Companies accepted the RSP as modified and approved by the PUCO in an August
4,
2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish
generation service rates beginning January 1, 2006, in response to PUCO concerns
about price and supply uncertainty following the end of the Ohio Companies'
transition plan market development period. In October 2004, the OCC and NOAC
filed appeals with the Supreme Court of Ohio to overturn the original
June 9, 2004 PUCO order in this proceeding as well as the associated
entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard
oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued
an opinion affirming that order with respect to the approval of the rate
stabilization charge, approval of the shopping credits, the grant of interest
on
shopping credit incentive deferral amounts, and approval of FirstEnergy’s
financial separation plan. It remanded the approval of the RSP pricing back
to
the PUCO for further consideration of the issue as to whether the RSP, as
adopted by the PUCO, provided for sufficient customer participation in the
competitive marketplace.
Under
provisions of
the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure
generation and allow for customer pricing participation in the competitive
marketplace. Any acceptance of future competitive bid results would terminate
the RSP pricing, with no accounting impacts to the RSP, and not until
12 months after the PUCO authorizes such termination. On December 9,
2004, the PUCO rejected the auction price results from the CBP for the
generation supply period beginning January 1, 2006 and issued an entry stating
that the pricing under the approved revised RSP would take effect on
January 1, 2006. On February 23, 2006 the CBP auction manager,
National Economic Research Associates, notified the PUCO that a subsequent
CBP
to potentially provide firm generation service for the Ohio Companies' 2007
and
2008 actual load requirements could not proceed due to lack of interest, as
there were no bidder applications submitted. Additionally, on March 20,
2006, the PUCO denied applications for rehearing filed by various parties
regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court
of Ohio opinion may require the PUCO to reconsider this customer pricing
process.
On January 4, 2006, the PUCO approved, with modifications, OE's RCP to
supplement the RSP to provide customers with more certain rate levels than
otherwise available under the RSP during the plan period. Major provisions
of
the RCP include:
|
·
|
Maintaining
the existing level of base distribution rates through December 31,
2008 for OE;
|
|
·
|
Deferring
and
capitalizing for future recovery (over a 25-year period) with carrying
charges certain distribution costs to be incurred by all of the Ohio
Companies during the period January 1, 2006 through December 31,
2008, not to exceed $150 million in each of the three
years;
|
|
·
|
Adjusting
the
RTC and extended RTC recovery periods and rate levels so that full
recovery of authorized costs will occur as of December 31, 2008 for
OE;
|
|
·
|
Reducing
the
deferred shopping incentive balance as of January 1, 2006 by up to
$75 million for OE by accelerating the application of its accumulated
cost of removal regulatory liability;
and
|
|
·
|
Recovering
increased fuel costs (compared to a 2002 baseline) of up to $75 million,
$77 million, and $79 million, in 2006, 2007, and 2008,
respectively, from all OE and TE distribution and transmission customers
through a fuel recovery mechanism. The Ohio Companies may defer and
capitalize (for recovery over a 25-year period) increased fuel costs
above
the amount collected through the fuel recovery mechanism (in lieu
of
implementation of the GCAF rider).
|
The following table provides OE’s estimated amortization of regulatory
transition costs and deferred shopping incentives (including associated carrying
charges) under the RCP for the period 2006 through 2008:
Amortization
|
|
|
|
Period
|
|
|
Amortization
|
|
|
|
(In
millions)
|
2006
|
|
$
|
172
|
2007
|
|
|
180
|
2008
|
|
|
206
|
Total
Amortization
|
|
$
|
558
|
The
PUCO’s January
4, 2006 approval of the RCP also included approval of the Ohio
Companies’
supplemental
stipulation which was filed with the PUCO on November 4, 2005 and which was
an
additional component of the RCP filed on September 9, 2005. On
January 10, 2006, the Ohio Companies filed a Motion for Clarification of
the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
related to distribution deferrals, including requirements of the review process,
timing for recognizing certain deferrals and definitions of the types of
qualified expenditures. The Ohio Companies also sought confirmation that the
list of deferrable distribution expenditures originally included in the revised
stipulation fall within the PUCO order definition of qualified expenditures.
On
January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
and denying in part, the Ohio Companies’ previous requests and clarifying issues
referred to above. The PUCO granted the Ohio Companies’ requests to:
|
·
|
Recognize
fuel
and distribution deferrals commencing January 1,
2006;
|
|
|
|
|
·
|
Recognize
distribution deferrals on a monthly basis prior to review by the
PUCO
Staff;
|
|
|
|
|
·
|
Clarify
that
the types of distribution expenditures included in the Supplemental
Stipulation may be deferred; and
|
|
|
|
|
·
|
Clarify
that
distribution expenditures do not have to be “accelerated” in order to be
deferred.
|
The
PUCO approved the
Ohio Companies’ methodology for determining distribution deferral amounts, but
denied the Motion in that the PUCO Staff must verify the level of distribution
expenditures contained in current rates, as opposed to simply accepting the
amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several
other parties filed applications for rehearing on the PUCO's January 4,
2006 Order. The Ohio Companies responded to the applications for rehearing
on
February 13, 2006. In an Entry on Rehearing issued by the PUCO on
March 1, 2006, all motions for rehearing were denied. Certain of these
parties have subsequently filed their notices of appeal with the Supreme Court
of Ohio alleging various errors made by the PUCO in its order approving the
RCP.
On
December 30,
2004, OE filed with the PUCO two applications related to the recovery of
transmission and ancillary service related costs. The first application sought
recovery of these costs beginning January 1, 2006. OE requested that these
costs be recovered through a rider that would be effective on January 1,
2006 and adjusted each July 1 thereafter. The parties reached a settlement
agreement that was approved by the PUCO on August 31, 2005. The incremental
transmission and ancillary service revenues expected to be recovered from
January through June 30, 2006 are approximately $34 million. This
amount includes the recovery of the 2005 deferred MISO expenses as described
below. On May 1, 2006, OE filed a modification to the rider to determine
revenues from July 2006 through June 2007.
The
second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO granted the
accounting authority for OE to defer incremental transmission and ancillary
service-related charges incurred as a participant in MISO, but only for those
costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 30, 2004 was denied. The PUCO also authorized OE to accrue
carrying charges on the deferred balances. On August 31, 2005, the OCC
appealed the PUCO's decision. All briefs have been filed. On March 20, 2006,
the
Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of OE's
case with a similar case involving Dayton Power & Light Company. Oral
argument is currently scheduled for May 10, 2006.
On
January 20,
2006, the OCC sought rehearing of the PUCO approval of the recovery of deferred
costs through the rider during the period January 1, 2006 through June 30,
2006. The PUCO denied the OCC's application on February 6, 2006. On March
23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
OCC's
brief is expected to be filed during the second quarter of 2006. The briefs
of
the PUCO and OE will be due within thirty days of the OCC's filing. On March
27,
2006, the OCC filed a motion to consolidate this appeal with the deferral
appeals discussed above and to postpone oral arguments in the deferral appeal
until after all briefs are filed in this most recent appeal of the rider
recovery mechanism. On
April 18, 2006,
the Court denied both parts of the motion but on its own motion consolidated
the
OCC's appeal of OE's case with a similar case of Dayton Power & Light
Company and stayed briefing on these appeals.
On
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for its
customers at set rates following the end of its transition period on
December 31, 2006. Penn recommended that the RFP process cover the period
January 1, 2007 through May 31, 2008. Hearings were held on
January 10, 2006 with main briefs filed on January 27, 2006 and reply
briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a
Recommended Decision to adopt Penn's RFP process with modifications. The PPUC
approved the Recommended Decision with additional modifications on
April 20, 2006. The approved plan is designed to provide customers with PLR
service for January 1, 2007 through May 31, 2008. Under Pennsylvania's
electric competition law, Penn is required to secure generation supply for
customers who do not choose alternative suppliers for their electricity.
On
November 1, 2005,
FES filed two power sales agreements for approval with the FERC. One power
sales
agreement provided for FES to provide the PLR requirements of the Ohio Companies
at a price equal to the retail generation rates approved by the PUCO for a
period of three years beginning January 1, 2006. The Ohio Companies will be
relieved of their obligation to obtain PLR power requirements from FES if the
Ohio competitive bid process results in a lower price for retail customers.
A
similar power sales agreement between FES and Penn permits Penn to obtain its
PLR power requirements from FES at a fixed price equal to the retail generation
price during 2006. The PPUC approved Penn's plan with modifications on April
20,
2006 to use an RFP process to obtain its power supply requirements after
2006.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio competitive bid process, and required
FES
to submit additional evidence in support of the reasonableness of the prices
charged in the power sales agreements. A pre-hearing conference was held on
January 18, 2006 to determine the hearing schedule in this case. FES
expects an initial decision to be issued in this case in late January 2007,
as a
result of the April 20, 2006 extension of the procedural schedule. The outcome
of this proceeding cannot be predicted. FES has sought rehearing of the
December 29, 2005 order and the FERC granted rehearing for future
consideration on March 1, 2006.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Ohio and Pennsylvania and a detailed
discussion of reliability initiatives, including initiatives by the PPUC, that
impact Penn.
Environmental
Matters
OE
accrues
environmental liabilities when it concludes that it is probable that it has
an
obligation for such costs and can reasonably estimate the amount of such costs.
Unasserted claims are reflected in OE’s determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
W.
H. Sammis
Plant
In
1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities alleging violations
of
the Clean Air Act based on operation and maintenance of 44 power plants,
including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
In addition, the DOJ filed eight civil complaints against various investor-owned
utilities, including 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. On March 18, 2005, OE and Penn announced that they had
reached a settlement with the EPA, the DOJ and three states (Connecticut, New
Jersey, and New York) that resolved all issues related to the W. H. Sammis
Plant
New Source Review litigation. This settlement agreement was approved by the
Court on July 11, 2005, and requires reductions of NOX
and SO2
emissions at the
W. H. Sammis Plant and other coal fired plants through the installation of
pollution control devices and provides for stipulated penalties for failure
to
install and operate such pollution controls in accordance with that agreement.
Consequently, if OE and Penn fail to install such pollution control devices,
for
any reason, including, but not limited to, the failure of any third-party
contractor to timely meet its delivery obligations for such devices, OE and
Penn
could be exposed to penalties under the settlement agreement. Capital
expenditures necessary to meet those requirements are currently estimated to
be
$1.5 billion (the primary portion of which is expected to be spent in the
2008 to 2011 time period). On August 26, 2005, FGCO entered into an
agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will
engineer, procure, and construct air quality control systems for the reduction
of sulfur dioxide emissions. The settlement agreement also requires OE and
Penn
to spend up to $25 million toward environmentally beneficial projects,
which include wind energy purchased power agreements over a 20-year term. OE
and
Penn agreed to pay a civil penalty of $8.5 million. Results for the first
quarter of 2005 included the penalties paid by OE and Penn of $7.8 million
and $0.7 million, respectively. OE and Penn also recognized liabilities in
the first quarter of 2005 of $9.2 million and $0.8 million,
respectively, for probable future cash contributions toward environmentally
beneficial projects.
See
Note 10(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal
Proceedings
There
are various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to OE’s normal business operations pending against OE and
its subsidiaries. The other potentially material items not otherwise discussed
above are described below.
Power
Outages
and Related Litigation-
On
August 14,
2003, various states and parts of southern Canada experienced widespread power
outages. The outages affected approximately 1.4 million customers in
FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages concluded, among other things, that
the problems leading to the outages began in FirstEnergy’s Ohio service area.
Specifically,
the
final report concluded, among other things, that the initiation of the
August 14, 2003 power outages resulted from 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 real-time 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 14, 2003 power
outages and that it does not adequately address the underlying causes of the
outages. FirstEnergy remains convinced that the outages cannot be explained
by
events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and
were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. FirstEnergy’s implementation of these
recommendations in 2004 included completion of the Task Force recommendations
that were directed toward FirstEnergy. FirstEnergy also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability that were to be completed subsequent to 2004 and will continue
to
periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new or material upgrades to existing
equipment, and therefore FirstEnergy has not accrued a liability as of
March 31, 2006 for any expenditure in excess of those actually incurred
through that date. The FERC or other applicable government agencies and
reliability coordinators may, however, take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room operators
before determining the next steps, if any, in the proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class action
complaints. Of the four other pending PUCO complaint cases, three were filed
by
various insurance carriers either in their own name as subrogees or in the
name
of their insured. In each of the four cases, the carrier seeks reimbursement
from various FirstEnergy companies (and, in one case, from PJM, MISO and
American Electric Power Company, Inc. as well) for claims paid to insureds
for
damages allegedly arising as a result of the loss of power on August 14,
2003. The listed insureds in these cases, in many instances, are not customers
of any FirstEnergy company. The fourth case involves the claim of a non-customer
seeking reimbursement for losses incurred when its store was burglarized on
August 14, 2003. On
March 7, 2006,
the PUCO issued a ruling applicable to all pending cases. Among its various
rulings, the PUCO consolidated all of the pending outage cases for hearing;
limited the litigation to service-related claims by customers of the Ohio
operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that
the
U.S.-Canada Power System Outage Task Force Report was not admissible into
evidence; and gave the plaintiffs additional time to amend their complaints
to
otherwise comply with the PUCO’s underlying order.
The plaintiffs in
one case have since filed an amended complaint. The named FirstEnergy companies
have answered and also have filed a motion to dismiss the action, which is
pending. Also, most complainants, along with the FirstEnergy companies, filed
applications for rehearing with the PUCO over various rulings contained in
the
March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
the
insurance company claimants, as insurers, to prosecute their claims in their
name so long as they also identify the underlying insured entities and the
Ohio
utilities which provide their service. The PUCO denied all other motions for
rehearing. No estimate of potential liability is available for any of these
cases. In addition to these six cases, the Ohio Companies were named as
respondents in a regulatory proceeding that was initiated at the PUCO in
response to complaints alleging failure to provide reasonable and adequate
service stemming primarily from the August 14, 2003 power outages.
Following the PUCO's March 7, 2006 order, that action was voluntarily
dismissed by the claimants.
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 the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.
Nuclear
Plant
Matters-
As
of
December 16, 2005, NGC acquired ownership of the nuclear generation assets
transferred from OE, Penn, CEI and TE with the exception of leasehold interests
of OE and TE in certain of the nuclear plants that are subject to sale and
leaseback arrangements with non-affiliates. Excluding OE's retained leasehold
interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%), the transfer
included the OE Companies’ prior owned interests in Beaver Valley Unit 1
(100%), Beaver Valley Unit 2 (33.96%) and Perry (22.66%).
On
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take prompt
and corrective action. FENOC operates the Perry Nuclear Power Plant.
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the
NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix. By an inspection report dated January 18, 2006, the NRC closed one
of the White Findings (related to emergency preparedness) which led to the
multiple degraded cornerstones.
On
September 28,
2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made
to
improve the performance at the Perry Plant and stated that the CAL would remain
open until substantial improvement was demonstrated. The CAL was anticipated
as
part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment
letter dated March 2, 2006 and associated meetings to discuss the performance
of
Perry on March 14, 2006, the NRC again stated that the Perry Plant
continued to operate in a manner that "preserved public health and safety."
However, the NRC also stated that increased levels of regulatory oversight
would
continue until sustained improvement in the performance of the facility was
realized. If performance does not improve, the NRC has a range of options under
the Reactor Oversight Process, from increased oversight to possible impact
to
the plant’s operating authority. Although FirstEnergy is unable to predict the
impact of the ultimate disposition of this matter, it could have a material
adverse effect on FirstEnergy's or its subsidiaries' financial condition,
results of operations and cash flows.
Other
Legal
Matters-
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have
become the subject of a formal order of investigation. The SEC's formal order
of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
FirstEnergy received a subpoena asking for background documents and documents
related to the restatements and Davis-Besse issues. On December 30, 2004,
FirstEnergy received a subpoena asking for documents relating to issues raised
during the SEC's PUHCA examination. On August 24, 2005 additional
information was requested regarding Davis-Besse related disclosures, which
FirstEnergy has provided. FirstEnergy has cooperated fully with the informal
inquiry and continues to do so with the formal investigation.
On
August 22,
2005, a class action complaint was filed against OE in Jefferson County, Ohio
Common Pleas Court, seeking compensatory and punitive damages to be determined
at trial based on claims of negligence and eight other tort counts alleging
damages from W.H. Sammis Plant air emissions. The two named plaintiffs are
also
seeking injunctive relief to eliminate harmful emissions and repair property
damage and the institution of a medical monitoring program for class members.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of a
newly-formed municipal electric utility. The complaint was filed on May 28,
2003, and OE timely filed its response on June 30, 2003. In a related
filing, the Ohio Companies filed for approval with the PUCO of a tariff that
would specifically allow the collection of transition charges from customers
of
municipal electric utilities formed after 1998. An adverse ruling could
negatively affect full recovery of transition charges by the utility. Hearings
on the matter were held in August 2005. Initial briefs from all parties were
filed on September 22, 2005 and reply briefs were filed on October 14,
2005. It is unknown when the PUCO will decide this case.
If it were ultimately determined that FirstEnergy or its subsidiaries have
legal
liability or are otherwise made subject to liability based on the above matters,
it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
See Note 10(C) to the consolidated financial statements for further details
and a complete discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or more
legally separate exchange transactions with the same counterparty should be
combined and considered as a single arrangement for purposes of applying
APB 29, when the transactions were entered into "in contemplation" of one
another. If two transactions are combined and considered a single arrangement,
the EITF reached a consensus that an exchange of inventory should be accounted
for at fair value. Although electric power is not capable of being held in
inventory, there is no substantive conceptual distinction between exchanges
involving power and other storable inventory. Therefore, OE will adopt this
EITF
effective for new arrangements entered into, or modifications or renewals of
existing arrangements, in interim or annual periods beginning after
March 15, 2006. This
EITF issue will
not have a material impact on OE's financial results.
SFAS
155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
Statements No. 133 and 140”
In
February 2006,
the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative
Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.”
This Statement permits fair value remeasurement for any hybrid financial
instrument that contains an embedded derivative that otherwise would require
bifurcation, clarifies which interest-only strips and principal-only strips
are
not subject to the requirements of SFAS 133, establishes a requirement to
evaluate interests in securitized financial assets to identify interests that
are freestanding derivatives or that are hybrid financial instruments that
contain an embedded derivative requiring bifurcation, clarifies that
concentrations of credit risk in the form of subordination are not embedded
derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
special-purpose entity from holding a derivative financial instrument that
pertains to a beneficial interest other than another derivative instrument.
This
Statement is effective for all financial instruments acquired or issued
beginning January 1, 2007. OE is currently evaluating the impact of this
Statement on its financial statements.
PENNSYLVANIA
POWER COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
|
|
|
|
2006
|
|
2005
|
|
STATEMENTS
OF INCOME
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
$
|
82,719
|
|
$
|
134,484
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
Fuel
|
|
|
-
|
|
|
5,620
|
|
|
Purchased
power
|
|
54,756
|
|
|
46,980
|
|
|
Nuclear
operating costs
|
|
-
|
|
|
19,948
|
|
|
Other
operating costs
|
|
14,204
|
|
|
12,768
|
|
|
Provision
for
depreciation
|
|
2,431
|
|
|
3,694
|
|
|
Amortization
of regulatory assets
|
|
3,411
|
|
|
9,882
|
|
|
General
taxes
|
|
5,834
|
|
|
6,472
|
|
|
Income
taxes
(benefit)
|
|
(251
|
) |
|
12,421
|
|
|
|
Total
operating expenses and taxes
|
|
80,385
|
|
|
117,785
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
2,334
|
|
|
16,699
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE) (net of income taxes)
|
|
2,333
|
|
|
(745
|
) |
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
Interest
on
long term debt
|
|
1,246
|
|
|
2,054
|
|
|
Allowance
for
borrowed funds used during construction
|
|
(34
|
) |
|
(1,367
|
) |
|
Other
interest
expense
|
|
2,709
|
|
|
265
|
|
|
|
Net
interest
charges
|
|
3,921
|
|
|
952
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
746
|
|
|
15,002
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
156
|
|
|
640
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
$
|
590
|
|
$
|
14,362
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
$
|
746
|
|
$
|
15,002
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
$
|
746
|
|
$
|
15,002
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral part of these statements.
|
|
PENNSYLVANIA
POWER COMPANY
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
(Unaudited)
|
|
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
thousands)
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
In
service
|
$
|
364,663
|
|
$
|
359,069
|
|
Less
-
Accumulated provision for depreciation
|
|
130,346
|
|
|
129,118
|
|
|
|
|
|
|
234,317
|
|
|
229,951
|
|
Construction
work in progress-
|
|
|
|
|
|
|
|
Electric
plant
|
|
2,301
|
|
|
3,775
|
|
|
|
|
|
|
236,618
|
|
|
233,726
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
283,125
|
|
|
283,248
|
|
Other
|
|
|
351
|
|
|
351
|
|
|
|
|
|
|
283,476
|
|
|
283,599
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
41
|
|
|
24
|
|
Notes
receivable from associated companies
|
|
10,833
|
|
|
1,699
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $1,092,000 and $1,087,000, respectively,
for uncollectible accounts)
|
|
39,510 |
|
|
44,555 |
|
|
Associated
companies
|
|
80,186
|
|
|
115,441
|
|
|
Other
|
|
1,239
|
|
|
2,889
|
|
Prepayments
and other
|
|
22,561
|
|
|
86,995
|
|
|
|
|
|
|
154,370
|
|
|
251,603
|
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
Prepaid
pension costs
|
|
42,649
|
|
|
42,243
|
|
Other
|
|
|
1,955
|
|
|
3,829
|
|
|
|
|
|
|
44,604
|
|
|
46,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
719,068
|
|
$
|
815,000
|
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
|
|
71,136
|
|
|
71,136
|
|
|
Retained
earnings
|
|
37,687
|
|
|
37,097
|
|
Preferred
stock
|
|
14,105
|
|
|
14,105
|
|
Long-term
debt
and other long-term obligations
|
|
123,807
|
|
|
130,677
|
|
|
|
|
|
|
435,435
|
|
|
441,715
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
22,424
|
|
|
69,524
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
|
Associated
companies
|
|
-
|
|
|
12,703
|
|
|
Other
|
|
19,000
|
|
|
-
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
20,538
|
|
|
73,444
|
|
|
Other
|
|
1,666
|
|
|
1,828
|
|
Accrued
taxes
|
|
32,806
|
|
|
28,632
|
|
Accrued
interest
|
|
1,059
|
|
|
1,877
|
|
Other
|
|
|
6,620
|
|
|
8,086
|
|
|
|
|
|
|
104,113
|
|
|
196,094
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
63,683
|
|
|
66,576
|
|
Retirement
benefits
|
|
46,429
|
|
|
45,967
|
|
Regulatory
liabilities
|
|
63,781
|
|
|
58,637
|
|
Other
|
|
|
5,627
|
|
|
6,011
|
|
|
|
|
|
|
179,520
|
|
|
177,191
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$
|
719,068
|
|
$
|
815,000
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral part of these balance sheets.
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
|
|
|
|
Restated
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
746
|
|
$
|
15,002
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
|
|
2,431
|
|
|
3,694
|
|
Amortization
of regulatory assets
|
|
|
|
|
|
3,411
|
|
|
9,882
|
|
Nuclear
fuel
and other amortization
|
|
|
|
|
|
-
|
|
|
4,140
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
|
|
|
(2,348
|
)
|
|
(2,311
|
)
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
|
|
|
41,950
|
|
|
11,892
|
|
Materials
and
supplies
|
|
|
|
|
|
-
|
|
|
218
|
|
Prepayments
and other current assets
|
|
|
|
|
|
(13,815
|
)
|
|
(13,481
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
|
|
|
(53,068
|
)
|
|
(2,890
|
)
|
Accrued
taxes
|
|
|
|
|
|
4,175
|
|
|
11,420
|
|
Accrued
interest
|
|
|
|
|
|
(819
|
)
|
|
(258
|
)
|
Other
|
|
|
|
|
|
1,607
|
|
|
778
|
|
Net
cash
provided from (used for) operating activities
|
|
|
|
|
|
(15,730
|
)
|
|
38,086
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
|
|
|
6,297
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
|
|
|
(54,462
|
)
|
|
-
|
|
Short-term
borrowings, net
|
|
|
|
|
|
-
|
|
|
(1,208
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
|
|
-
|
|
|
(8,000
|
)
|
Preferred
stock
|
|
|
|
|
|
(156
|
)
|
|
(640
|
)
|
Net
cash used
for financing activities
|
|
|
|
|
|
(48,321
|
)
|
|
(9,848
|
)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
|
|
|
(5,114
|
)
|
|
(28,522
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
|
|
|
-
|
|
|
13,703
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
|
|
|
-
|
|
|
(14,102
|
)
|
Loans
to
associated companies
|
|
|
|
|
|
(9,010
|
)
|
|
(19
|
)
|
Cash
investments
|
|
|
|
|
|
78,248
|
|
|
-
|
|
Other
|
|
|
|
|
|
(56
|
)
|
|
702
|
|
Net
cash
provided from (used for) investing activities
|
|
|
|
|
|
64,068
|
|
|
(28,238
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
|
|
|
17
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
|
|
|
24
|
|
|
38
|
|
Cash
and cash
equivalents at end of period
|
|
|
|
|
$
|
41
|
|
$
|
38
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral part of these
statements
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Pennsylvania Power Company:
We
have reviewed the
accompanying consolidated balance sheet of Pennsylvania Power Company and its
subsidiaries as of March 31, 2006, and the related consolidated statements
of
income and comprehensive income and cash flows for each of the three-month
periods ended March 31, 2006 and 2005. 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
described in the
section entitled "Restatement of the Consolidated Statements of Cash Flows"
included in Note 1 to the consolidated interim financial statements, the Company
has restated its previously issued consolidated interim financial statements
for
the quarter ended March 31, 2006.
We
have previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2005, and the related consolidated statements of income, capitalization,
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 2(G) and Note 8 to those
consolidated financial statements] dated February 27, 2006, 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, 2005, is fairly stated in all material respects in relation to
the
consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May
8, 2006,
except as to Note 1, which is as of October 31,
2006
|
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 Penn
as
their power supplier. Penn's rate restructuring plan and its associated
transition charge revenue recovery was completed in 2005. Its power supply
requirements are provided by FES - an affiliated company.
FirstEnergy
Intra-System Generation Asset Transfers
On
May 13, 2005,
Penn, and on May 18, 2005, the Ohio Companies, entered into certain
agreements implementing a series of intra-system generation asset transfers
that
were completed in the fourth quarter of 2005. The asset transfers resulted
in
the respective undivided ownership interests of the Ohio Companies and Penn
in
FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
FGCO, respectively.
On October 24, 2005, Penn completed the intra-system transfer of non-nuclear
generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master
Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
the non-nuclear generation assets that it now owns. The asset transfers were
consummated pursuant to FGCO's purchase option under the Master Facility
Lease.
On December 16, 2005, Penn completed the intra-system transfer of its ownership
interests in the nuclear generation assets to NGC through an asset spin-off
in
the form of a dividend. FENOC continues to operate and maintain the nuclear
generation assets.
These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s
restructuring plans that were approved by the PUCO and the PPUC, respectively,
under applicable Ohio and Pennsylvania electric utility restructuring
legislation. Consistent with the restructuring plans, generation assets that
had
been owned by the Ohio Companies and Penn were required to be separated from
the
regulated delivery business of those companies through transfer to a separate
corporate entity. The transactions essentially completed the divestitures
contemplated by the restructuring plans by transferring the ownership interests
to NGC and FGCO without impacting the operation of the plants.
The
transfers
will
affect Penn’s near-term results with reductions in both revenues and expenses.
Revenues are reduced due to the termination of certain arrangements with FES,
under which Penn previously sold its nuclear-generated KWH to FES and leased
its
non-nuclear generation assets to FGCO, a subsidiary of FES. Penn’s expenses are
lower due to the nuclear fuel and operating costs assumed by NGC as well as
depreciation and property tax expenses assumed by FGCO and NGC related to the
transferred generating assets. In addition, Penn receives interest income on
associated company notes receivable from the transfer of its generation net
assets. FES will continue to provide Penn’s PLR requirements under revised
purchased power arrangements for the three-year period beginning January 1,
2006 (see Outlook -- Regulatory Matters).
The
effects on
Penn’s results of operations in the first quarter of 2006 compared to the first
quarter of 2005 from the generation asset transfers are summarized in the
following table:
Intra-System
Generation Asset Transfers
|
|
|
First
Quarter 2006 vs. First Quarter 2005 Income Statement
Effects
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
|
Operating
Revenues:
|
|
|
|
|
Non-nuclear
generating units rent
|
|
$
|
(5
|
)
|
(a)
|
|
Nuclear
generated KWH sales
|
|
|
(39
|
)
|
(b)
|
|
Total
-
Operating Revenues Effect
|
|
|
(44
|
)
|
|
|
Operating
Expenses and Taxes:
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
|
|
(6
|
)
|
(c)
|
|
Nuclear
operating costs
|
|
|
(20
|
)
|
(c)
|
|
Provision
for
depreciation
|
|
|
(2
|
)
|
(d)
|
|
Income
taxes
|
|
|
(7
|
)
|
(g)
|
|
Total-
Operating Expenses and Taxes Effect
|
|
|
(35
|
)
|
|
|
Operating
Income Effect
|
|
|
(9
|
)
|
|
|
Other
Income:
|
|
|
|
|
|
|
Interest
income from notes receivable
|
|
|
2
|
|
(e)
|
|
Income
taxes
|
|
|
1
|
|
(g)
|
|
Total-Other
Income Effect
|
|
|
1
|
|
|
|
Net
interest
Charges:
|
|
|
|
|
|
|
Allowance
for
funds used during construction
|
|
|
(1
|
)
|
(f)
|
|
Total-Net
Interest Charges Effect
|
|
|
1
|
|
|
|
Net
Income
Effect
|
|
$
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
(a)
Elimination of non-nuclear generation assets lease to
FGCO.
|
(b)
Reduction
of nuclear generated wholesale KWH sales to FES.
|
(c)
Reduction
of nuclear fuel and operating costs.
|
(d)
Reduction
of depreciation expense and asset retirement obligation accretion
related
to generation
assets.
|
(e)
Interest
income on associated company notes receivable from the transfer
of
generation net assets.
|
(f)
Reduction
of allowance for borrowed funds used during construction on nuclear
capital expenditures.
|
(g)
Income tax
effect of the above adjustments.
|
|
Restatement
of Consolidated Statement of Cash Flows
As
further discussed
in Note 1 to the Consolidated Financial Statements, Penn is restating its
Consolidated Statement of Cash Flows for the three months ended March 31,
2006.
This corrects a misclassification of a $78 million cash receipt from the
liquidation of cash investments (restricted cash related to the 2005 generation
asset transfers) in the first quarter of 2006. The cash receipt was previously
reported in cash flows from operating activities and should have been reported
in cash flows from investing activities. This correction resulted in a $78
million decrease in the previously reported cash flows from operating activities
and a corresponding increase in cash flows from investing activities in Penn’s
Consolidated Statements of Cash Flows for the three months ended March 31,
2006.
This resulted in revisions in the previously reported Management’s Discussion
and Analysis of Results of Operations only to Capital Resources and Liquidity
under the Cash Flows From Operating Activities and Cash Flows From Investing
Activities sections. The correction does not change Penn’s previously reported
consolidated statements of income and comprehensive income for the three
months
ended March 31, 2006 or its consolidated balance sheet as of March 31, 2006.
Results
of Operations
Earnings
on common
stock in the first quarter of 2006 decreased to $0.6 million from
$14 million in the first quarter of 2005. The lower earnings resulted
principally from the generation asset transfer effects shown in the table above.
Operating
Revenues
Operating
revenues
decreased by $52 million, or 39%, in the first quarter of 2006 as compared
with
the first quarter of 2005, primarily due to the generation asset transfer impact
discussed in the table above. Excluding the effects of the asset transfer,
operating revenues decreased by $8 million, or 9%. That decrease resulted from
lower distribution revenues of $9 million primarily reflecting the
completion of Penn's transition costs recovery, and lower wholesale revenues
of
$6 million resulting from the termination of a wholesale sales agreement
with a non-affiliate in December 2005. The decrease in distribution KWH
deliveries to residential and commercial customers reflected milder weather
in
the first quarter of 2006. The distribution and wholesale revenue decreases
were
partially offset by an increase in retail generation revenues of $6 million,
primarily from higher composite unit prices associated with a 5% rate increase
permitted by the PPUC for all customer classes - retail generation KWH sales
remained substantially unchanged.
Changes
in
distribution deliveries in the first quarter of 2006 from the same period of
2005 are summarized in the following table:
Changes
in Distribution Deliveries
|
|
|
Increase
(Decrease)
|
|
|
Residential
|
|
(3)%
|
Commercial
|
|
(1)%
|
Industrial
|
|
4
%
|
Total
Distribution Deliveries
|
|
-
%
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes decreased by $37 million in the first quarter of 2006 from
the first quarter of 2005 principally due to the generation asset transfer
impact as shown in the table above. Excluding the asset transfer effects, the
following presents changes from the prior year by expense category:
Operating
Expenses and Taxes - Changes (In
millions)
|
|
|
|
Increase
(Decrease)
|
|
|
|
Purchased
power costs
|
|
$
|
8
|
|
Other
operating costs
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
(6
|
)
|
Income
taxes
|
|
|
(5
|
)
|
Total
operating expenses and taxes
|
|
$
|
(2
|
)
|
Increased
purchased
power costs in the first quarter of 2006, compared with the first quarter of
2005, resulted from higher unit prices associated with the new power supply
agreement with FES, partially offset by a 13% decrease in KWH purchased due
to
lower generation sales requirements. Other operating costs increased due to
transmission expenses associated with MISO Day 2 operations that began in April
2005.
Amortization
of
regulatory assets was lower in the first quarter of 2006 as compared to the
same
period of 2005 due to the completion of Penn's rate restructuring plan and
related transition cost amortization.
Other
Income
(Expense)
Other
income
increased $3 million in the first quarter of 2006, compared with the first
quarter of 2005, in part due to the impact of the generation asset transfer.
Excluding the effects of the asset transfer, other income was $2 million
higher. This increase was primarily due to the absence in 2006 of accruals
for a
$0.7 million civil penalty payable to the DOJ and $0.8 million settlement
for environmental projects in connection with the Sammis New Source Review
settlement in the first quarter of 2005 (see Environmental
Matters).
Net
Interest
Charges
Excluding
the
effects of the asset transfer, net interest charges increased by $2 million
in the first quarter of 2006, as compared to the first quarter of 2005. This
increase was primarily due to a loss incurred on reacquired pollution control
notes in the first quarter of 2006.
Capital
Resources and Liquidity
Penn’s
cash
requirements in 2006 for operating expenses, construction expenditures and
scheduled debt maturities are expected to be met with
a combination
of cash from operations and short-term credit arrangements.
Available borrowing
capacity under credit facilities will be used to manage working capital
requirements.
Changes
in Cash
Position
Penn
had $41,000 of
cash and cash equivalents as of March 31, 2006 compared with $24,000 as of
December 31, 2005. The major sources for changes in these balances are
summarized below.
Cash
Flows From
Operating Activities
Net
cash of $16
million (as restated) used for operating activities in the first quarter of
2006, compared with the corresponding 2005 period, was as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings(1)
|
|
$
|
4
|
|
$
|
30
|
|
Working
capital and other
|
|
|
(20)
|
|
|
8
|
|
|
|
|
|
|
|
|
|
Net
cash
provided from (used for) operating activities
|
|
$
|
(16)
|
|
$
|
38
|
|
(1) Cash
earnings are a
non-GAAP measure (see reconciliation below).
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. Penn believes that cash earnings are a useful financial measure because
it
provides investors and management with an additional means of evaluating its
cash-based operating performance. The following table reconciles cash earnings
with net income:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
Income
(GAAP)
|
|
$
|
1
|
|
$
|
15
|
|
Non-Cash
Charges (Credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
2
|
|
|
3
|
|
Amortization
of regulatory assets
|
|
|
3
|
|
|
10
|
|
Nuclear
fuel
and other amortization
|
|
|
-
|
|
|
4
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(2)
|
|
|
(2
|
)
|
Other
non-cash
expenses
|
|
|
-
|
|
|
-
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
4
|
|
$
|
30
|
|
The
$26 million
decrease in cash earnings is described above under “Results of Operations.” The
$28 million decrease in working capital was primarily due to increased cash
outflows from the settlement of accounts payable of $50 million and a
$7 million change in accrued taxes, partially offset by increases in cash
provided from the settlement of receivables of $30 million.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities totaled $48 million in the first quarter of 2006, compared
with $10 million in the first quarter of 2005. This increase resulted from
$54 million of long-term debt redemptions in 2006 principally as a result of
the
generation asset transfer discussed above, partially offset by a net $8 million
increase in short-term borrowings and the absence of $8 million in common
stock dividend payments to OE in the first quarter of 2005.
Penn
had $11 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and $19 million of short-term indebtedness as of
March 31, 2006. Penn has authorization from the SEC, continued by FERC
rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt
up to its charter limit of $50 million (including the utility money pool).
Penn had the capability to issue $64 million of additional FMB on the basis
of property additions and retired bonds as of March 31, 2006. Based upon
applicable earnings coverage tests, Penn could issue up to $415 million of
preferred stock (assuming no additional debt was issued) as of March 31,
2006.
Penn
Power Funding
LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
company whose borrowings are secured by customer accounts receivable purchased
from Penn. Penn Funding can borrow up to the full amount of $25 million
available as of March 31, 2006 under a receivables financing arrangement
which expires June 29, 2006. As a separate legal entity with separate
creditors, Penn Funding would have to satisfy its obligations to creditors
before any of its remaining assets could be made available to Penn. As
of March 31,
2006, the facility was drawn for $19 million.
Penn
has the ability
to borrow under a syndicated $2 billion five-year revolving credit facility,
which expires in June 2010, along with FirstEnergy, OE, CEI, TE, JCP&L,
Met-Ed, Penelec, FES, and ATSI. Borrowings under the facility are available
to
each Borrower separately and will mature on the earlier of 364 days from the
date of borrowing or the commitment termination date. Penn's borrowing limit
under the facility is $50 million.
Under
the revolving
credit facility, borrowers may request the issuance of letters of credit
expiring up to one year from the date of issuance. The stated amount of
outstanding letters of credit will count against total commitments available
under the facility and against the applicable borrower’s borrowing sub-limit.
Total unused borrowing capability under the existing credit facility and
accounts receivable financing facilities totaled $56 million as of
March 31, 2006.
The
revolving credit
facility contains financial covenants requiring each borrower to maintain a
consolidated debt to total capitalization ratio of no more than 65%. As of
March 31, 2006, Penn's debt to total capitalization as defined under the
revolving credit facility was 35%.
The
facility does
not contain any provisions that either restrict Penn's ability to borrow or
accelerate repayment of outstanding advances as a result of any change in its
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to Penn's credit ratings.
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. 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 under these arrangements in the first quarter
of
2006 was 4.58%.
Penn's
access to the
capital markets and the costs of financing are influenced by the ratings of
its
securities and the securities of OE and FirstEnergy. The rating outlook from
S&P on all securities is stable. Moody's and Fitch's ratings outlook on all
securities is positive.
In
April 2006, pollution control notes that were formerly obligations of Penn
were
refinanced and became obligations of FGCO and NGC. The proceeds from the
refinancings were used to repay a portion of their associated company notes
payable to Penn. With those repayments, Penn redeemed pollution control notes
in
the principal amount of $6.95 million at 5.45%.
Cash
Flows From
Investing Activities
Net
cash provided
from investing activities totaled $64 million (as restated) in the first quarter
of 2006, compared with net cash of $28 million used for investing
activities in the same quarter of 2005. The $92 million change reflects $78
million from the liquidation of cash investments (restricted cash related to
the
2005 generation asset transfers), a $23 million reduction in property additions,
principally as a result of the generation asset transfers discussed above,
partially offset by a $9 million increase in loans to associated
companies.
During
the remaining
three quarters of 2006, capital requirements for property additions are expected
to be about $14 million. Penn has sinking fund requirements of
approximately $1 million for maturing long-term debt during the remainder
of 2006. These cash requirements are expected to be satisfied from internal
cash
and short-term credit arrangements.
Penn’s
capital
spending for the period 2006-2010 is expected to be about $91 million of which
approximately $19 million applies to 2006. Penn had no other material
obligations as of March 31, 2006 that have not been recognized on its
Consolidated Balance Sheet.
OUTLOOK
The electric industry continues to transition to a more competitive environment
and all of Penn’s customers can select alternative energy suppliers. Penn
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. 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.
Regulatory
Matters
Regulatory assets and liabilities are costs which have been authorized by the
PPUC and the FERC for recovery from or credit to customers in future periods
and, without such authorization, would have been charged or credited to income
when incurred. Penn’s net regulatory liabilities were approximately
$64 million and $59 million as of March 31, 2006 and
December 31, 2005, respectively, and are included under Noncurrent
Liabilities on the Consolidated Balance Sheets.
On October 11, 2005, Penn filed a plan with the PPUC to secure electricity
supply for its customers at set rates following the end of its transition period
on December 31, 2006. Penn recommended that an RFP process cover the period
January 1, 2007 through May 31, 2008. Hearings were held on
January 10, 2006 with main briefs filed on January 27, 2006 and reply
briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued
a Recommended Decision to adopt Penn's RFP process with modifications. The
PPUC
approved the Recommended Decision with additional modifications on April 20,
2006. The approved plan is designed to provide customers with PLR service for
January 1, 2007 through May 31, 2008. Under Pennsylvania's electric
competition law, Penn is required to secure generation supply for customers
who
do not choose alternative suppliers for their electricity.
On November 1, 2005, FES filed a power sales agreement for FERC approval that
would permit Penn to obtain its PLR power requirements from FES at a fixed
price
equal to the retail generation price during 2006. On December 29, 2005, the
FERC issued an order setting the power sales agreement for hearing. The order
required FES to submit additional evidence in support of the reasonableness
of
the prices charged in Penn’s contract. A pre-hearing conference was held on
January 18, 2006 to determine the hearing schedule in this case. FES
expects an initial decision to be issued in this case in late January 2007,
as a
result of an April 20, 2006 extension of the procedural schedule. The outcome
of
this proceeding cannot be predicted. FES has sought rehearing of the
December 29, 2005 order and the FERC granted rehearing for further
consideration on March 1, 2006.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Pennsylvania.
Environmental
Matters
Penn
accrues environmental liabilities when it concludes that it is probable that
it
has an obligation for such costs and can reasonably estimate the amount of
such
costs. Unasserted claims are reflected in Penn’s determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
W.
H. Sammis
Plant
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
alleging violations of the Clean Air Act based on operation and maintenance
of
44 power plants, including the W. H. Sammis Plant, which was owned at that
time
by OE and Penn. In addition, the DOJ filed eight civil complaints against
various investor-owned utilities, including 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. On March 18, 2005, OE and Penn
announced that they had reached a settlement with the EPA, the DOJ and three
states (Connecticut, New Jersey, and New York) that resolved all issues related
to the W. H. Sammis Plant New Source Review litigation. This
settlement
agreement was approved by the Court on July 11, 2005, and requires
reductions of NOx
and SO2
emissions at the
W. H. Sammis Plant and other coal fired plants through the installation of
pollution control devices and provides for stipulated penalties for failure
to
install and operate such pollution controls in accordance with that
agreement.
Consequently, if OE
and Penn fail to install such pollution control devices, for any reason,
including, but not limited to, the failure of any third-party contractor to
timely meet its delivery obligations for such devices, OE and Penn could be
exposed to penalties under the settlement agreement. Capital expenditures
necessary to meet those requirements are currently estimated to be
$1.5 billion (the primary portion of which is expected to be spent in the
2008 to 2011 time period). On August 26, 2005, FGCO entered into an
agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will
engineer, procure, and construct air quality control systems for the reduction
of sulfur dioxide emissions. The settlement agreement also requires OE and
Penn
to spend up to $25 million toward environmentally beneficial projects,
which include wind energy purchased power agreements over a 20-year term. OE
and
Penn agreed to pay a civil penalty of $8.5 million. Results for the first
quarter of 2005 included the penalties payable by OE and Penn of
$7.8 million and $0.7 million, respectively. OE and Penn also
recognized liabilities of $9.2 million and $0.8 million, respectively,
for
probable future cash contributions toward environmentally beneficial
projects.
Other
Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure)
and
proceedings related to Penn’s normal business operations pending against Penn.
The other material items not otherwise discussed above are described
below.
Power
Outages and Related Litigation-
On August 14, 2003, various states and parts of southern Canada experienced
widespread power outages. The outages affected approximately 1.4 million
customers in FirstEnergy’s service area. The U.S. - Canada Power System Outage
Task Force’s final report in April 2004 on the outages concludes, among other
things, that the problems leading to the outages began in FirstEnergy’s Ohio
service area. Specifically,
the
final report concluded, among other things, that the initiation of the
August 14, 2003 power outages resulted from 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 real-time 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 14, 2003 power
outages and that it does not adequately address the underlying causes of the
outages. FirstEnergy remains convinced that the outages cannot be explained
by
events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and
were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. FirstEnergy’s implementation of these
recommendations in 2004 included completion of the Task Force recommendations
that were directed toward FirstEnergy. FirstEnergy also is proceeding with
the
implementation
of the
recommendations regarding enhancements to regional reliability that were to
be
completed subsequent to 2004 and will continue to periodically assess the
FERC-ordered Reliability Study recommendations for forecasted 2009 system
conditions, recognizing revised load forecasts and other changing system
conditions which may impact the recommendations. Thus far implementation of
the
recommendations has not required, nor is expected to require, substantial
investment in new or material upgrades, to existing equipment, and therefore
FirstEnergy has not accrued a liability as of March 31, 2006 for any
expenditure in excess of those actually incurred through that date. The 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.
Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed
upgrades to control room computer hardware and software and enhancements to
the
training of control room operators before determining the next steps, if any,
in
the proceeding.
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 the Companies. In particular, if FirstEnergy or its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition and results of operations.
See Note 10(C) to the consolidated financial statements for further details
and a complete discussion of other legal proceedings.
New
Accounting Standards and Interpretations
|
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the
Same
Counterparty"
|
In
September 2005, the EITF reached a final consensus on Issue 04-13 concluding
that two or more legally separate exchange transactions with the same
counterparty should be combined and considered as a single arrangement for
purposes of applying APB 29, when the transactions were entered into "in
contemplation" of one another. If two transactions are combined and considered
a
single arrangement, the EITF reached a consensus that an exchange of inventory
should be accounted for at fair value. Although electric power is not capable
of
being held in inventory, there is no substantive conceptual distinction between
exchanges involving power and other storable inventory. Therefore, Penn adopted
adopt this EITF effective for new arrangements entered into, or modifications
or
renewals of existing arrangements, in interim or annual periods beginning after
March 15, 2006. This
EITF issue will
not have a material impact on Penn's financial results.
SFAS
155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
Statements No. 133 and 140”
In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities.” This Statement permits fair value remeasurement for any hybrid
financial instrument that contains an embedded derivative that otherwise would
require bifurcation, clarifies which interest-only strips and principal-only
strips are not subject to the requirements of SFAS 133, establishes a
requirement to evaluate interests in securitized financial assets to identify
interests that are freestanding derivatives or that are hybrid financial
instruments that contain an embedded derivative requiring bifurcation, clarifies
that concentrations of credit risk in the form of subordination are not embedded
derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
special-purpose entity from holding a derivative financial instrument that
pertains to a beneficial interest other than another derivative instrument.
This
Statement is effective for all financial instruments acquired or issued
beginning January 1, 2007. Penn is currently evaluating the impact of this
Statement on its financial statements.
ITEM
4.
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. The term
disclosure controls and procedures means controls and other procedures of
a
registrant that are designed to ensure that information required to be disclosed
by the registrant in the reports that it files or submits under the Securities
Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized
and reported, within the time periods specified in the Securities and Exchange
Commission's rules and forms. Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by an issuer in the reports that it files or submits
under that Act is accumulated and communicated to the registrant's management,
including its principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure. Based upon that evaluation, those officers concluded
that,
as of the end of the period covered by this report, the applicable registrant's
disclosure controls and procedures were ineffective as of March 31, 2006.
As
reported in this
Form 10-Q/A, the registrants have amended their Form 10-Q for the first quarter
of 2006 to restate their respective Consolidated Statements of Cash Flows
for a
misclassification between cash from operating activities and cash from investing
activities. The restatement did not affect the registrants’ Consolidated
Statements of Income and Comprehensive Income or Consolidated Balance Sheets.
The
restatement
resulted solely from the misclassification of cash flows related to cash
receipts from the liquidation of a temporary cash investment (restricted
cash
related to the 2005 generation asset transfer), as fully discussed in Note
1 to
the accompanying consolidated interim financial statements. The cash flows
had
been classified in operating activities, rather than investing activities.
Accordingly, the restatements will solely affect the classification of these
activities and the subtotals of cash flows from operating and investing
activities presented in the affected Consolidated Statements of Cash Flows,
but
will have no impact on the net increase (decrease) in total cash and cash
equivalents for the quarter ended March 31, 2006.
The
restatement
described above resulted from a deficiency in the internal controls over
the
preparation and review of the Consolidated Statement of Cash Flows. The
registrants modified the internal controls over the preparation and review
of
their Consolidated Statements of Cash Flows during the third quarter of 2006.
Management has implemented a process to aid in ensuring the correct
classification of items included in the consolidated statement of cash flows,
including a control over the preparation and review of manual reclassifications.
Accordingly, management believes that this enhancement accentuates the existing
internal controls and remediated the control deficiency discussed above.
There
have been no other changes made in the registrants' internal control over
financial reporting that occurred during the registrants’ third quarter of 2006
that have materially affected, or are reasonably likely to materially affect,
the registrants' internal control over financial reporting. Based on the
remediation of the control deficiency, the applicable registrant's chief
executive officer and chief financial officer have concluded that the disclosure
controls and procedures were effective as of the filing date of this amended
Form 10-Q.
PART
II. OTHER INFORMATION
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
FirstEnergy
|
|
|
|
|
10.1*
|
(a)
|
Form
of
Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp.
in favor
of the Participating Banks, Barclays Bank PLC, as administrative
agent and
fronting bank, and KeyBank National Association, as syndication agent,
under the related Letter of Credit and Reimbursement
Agreement.
|
10.2*
|
(a)
|
Form
of Letter
of Credit and Reimbursement Agreement dated as of April 3, 2006 among
FirstEnergy Generation Corp., the Participating Banks, Barclays Bank
PLC,
as administrative agent and fronting bank, and KeyBank National
Association, as syndication agent.
|
10.3*
|
(a)
|
Form
of Trust
Indenture dated as of April 1, 2006 between the Ohio Water Development
Authority and The Bank of New York Trust Company, N.A. as Trustee
securing
pollution control revenue refunding bonds issued on behalf of FirstEnergy
Generation Corp.
|
10.4*
|
(a)
|
Form
of Waste
Water Facilities Loan Agreement between the Ohio Water Development
Authority and FirstEnergy Generation Corp. dated as of April 1,
2006.
|
10.5
|
(a)
|
Notice
of
Termination Tolling Agreement dated as of April 7, 2006; Restated
Partial
Requirements Agreement, dated January 1, 2003, by and among, Metropolitan
Edison Company, Pennsylvania Electric Company, The Waverly Electric
Power
and Light Company and FirstEnergy Solutions Corp., as amended by
a First
Amendment to Restated Requirements Agreement, dated August 29, 2003
and by
a Second Amendment to Restated Requirements Agreement, dated June
8, 2004
(“Partial Requirements Agreement”). (Form 8-K dated April 10,
2006)
|
10.6
|
(a)
|
Form
of
Restricted Stock Agreement between FirstEnergy and A. J. Alexander,
dated
February 27, 2006.
|
10.7
|
(a)
|
Form
of
Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy
and A.J. Alexander, dated March 1, 2006.
|
10.8
|
(a)
|
Form
of
Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy
and named executive officers, dated March 1, 2006.
|
10.9
|
(a)
|
Form
of
Restricted Stock Unit Agreement (Discretionary) between FirstEnergy
and
R.H. Marsh, dated March 1, 2006.
|
12
|
(a)
|
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
|
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
OE
|
|
|
|
|
12
|
(a)
|
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
|
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
Penn
|
|
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
|
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
*
Three
substantially similar agreements, each dated as of the same date,
were
executed and delivered by the registrant and its affiliates with
respect
to three other series of pollution control revenue refunding bonds
issued
by the Ohio Water Development Authority and the Beaver County Industrial
Development Authority relating to pollution control notes of FirstEnergy
Generation Corp. and FirstEnergy Nuclear Generation Corp. (Form 8-K
dated
April 3, 2006)
|
(a)
|
Indicates
the
items that have not been revised and are not included in this Form
10-Q/A.
Reference is made to the original Form 10-Q filed on May 9, 2006
for the
complete text of such items.
|
Pursuant
to
reporting requirements of respective financings, FirstEnergy and OE are required
to file fixed charge ratios as an exhibit to this Form 10-Q. Penn does not
have
similar financing reporting requirements and has not filed its fixed charge
ratios.
Pursuant
to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
OE
and Penn 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
and Penn but hereby agree to furnish to the Commission on request any such
documents.
SIGNATURE
Pursuant
to the
requirements of the Securities Exchange Act of 1934, each Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto
duly
authorized.
November
1,
2006
|
FIRSTENERGY
CORP.
|
|
Registrant
|
|
|
|
OHIO
EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
POWER COMPANY
|
|
Registrant
|
|
|
|
/s/ Harvey
L.
Wagner
|
|
Harvey L. Wagner
|
|
Vice President, Controller
|
|
and Chief Accounting Officer
|