Form 10-Q 3rd Quarter September 30, 2006
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D. C. 20549
FORM
10-Q
(Mark
One)
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the
quarterly period ended September 30, 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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1-2323
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THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
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34-0150020
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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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1-3583
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THE
TOLEDO EDISON COMPANY
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34-4375005
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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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1-3141
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JERSEY
CENTRAL POWER & LIGHT COMPANY
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21-0485010
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(A
New
Jersey 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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1-446
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METROPOLITAN
EDISON COMPANY
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23-0870160
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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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1-3522
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PENNSYLVANIA
ELECTRIC COMPANY
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25-0718085
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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)
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FirstEnergy
Corp.
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Accelerated
Filer ( )
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N/A
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Non-accelerated
Filer (X)
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Ohio
Edison
Company, The Cleveland Electric Illuminating Company, The Toledo
Edison
Company, Pennsylvania Power Company, Jersey Central Power & Light
Company, Metropolitan Edison Company, and Pennsylvania Electric
Company
|
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:
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OUTSTANDING
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CLASS
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AS
OF OCTOBER 31, 2006
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FirstEnergy
Corp., $.10 par value
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319,205,517
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Ohio
Edison
Company, no par value
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80
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The
Cleveland
Electric Illuminating Company, no par value
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79,590,689
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The
Toledo
Edison Company, $5 par value
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39,133,887
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Pennsylvania
Power Company, $30 par value
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6,290,000
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Jersey
Central
Power & Light Company, $10 par value
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15,371,270
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Metropolitan
Edison Company, no par value
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859,500
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Pennsylvania
Electric Company, $20 par value
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5,290,596
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FirstEnergy
Corp. is
the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company common stock.
Ohio
Edison Company is the sole holder of Pennsylvania Power Company common stock.
This
combined Form
10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, The
Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania
Power Company, Jersey Central Power & Light Company, Metropolitan Edison
Company and Pennsylvania Electric Company. Information contained herein relating
to any individual registrant is filed by such registrant on its own behalf.
No
registrant makes any representation as to information relating to any other
registrant, except that information relating to any of the FirstEnergy
subsidiary registrants is also attributed to FirstEnergy Corp.
This Form 10-Q includes forward-looking statements based on information
currently available to management. Such statements are subject to certain risks
and uncertainties. These statements typically contain, but are not limited
to,
the terms "anticipate," "potential," "expect," "believe," "estimate" and similar
words. Actual results may differ materially due to the speed and nature of
increased competition and deregulation in the electric utility industry,
economic or weather conditions affecting future sales and margins, changes in
markets for energy services, changing energy and commodity market prices,
replacement power costs being higher than anticipated or inadequately hedged,
the continued ability of FirstEnergy Corp.’s 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 needed to, among other things, implement the Air Quality Compliance
Plan (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 (including,
but not
limited to, the successful resolution of the issues remanded to the
Public Utilities Commissioni of Ohio by the Ohio Supreme Court
regarding the Rate Stabilization Plan) 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
outages, the successful completion of the share repurchase program announced
on
August 10, 2006, 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. A security rating is not a recommendation to buy, sell or
hold
securities and it may be subject to revision or withdrawal at any time by the
credit rating agency. 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.
TABLE
OF
CONTENTS
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Pages
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Glossary
of Terms
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iii-v
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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
Financial
Condition and Results of Operations.
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Notes
to
Consolidated Financial Statements
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1-30
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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31
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Consolidated
Statements of Comprehensive Income
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32
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Consolidated
Balance Sheets
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33
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Consolidated
Statements of Cash Flows
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34
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Report
of
Independent Registered Public Accounting Firm
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35
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Management's
Discussion and Analysis of Results of Operations and
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36-76
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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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77
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Consolidated
Balance Sheets
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78
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Consolidated
Statements of Cash Flows
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79
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Report
of
Independent Registered Public Accounting Firm
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80
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Management's
Discussion and Analysis of Results of Operations and
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81-96
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Financial
Condition
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The
Cleveland Electric Illuminating Company
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Consolidated
Statements of Income and Comprehensive Income
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97
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Consolidated
Balance Sheets
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98
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Consolidated
Statements of Cash Flows
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99
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Report
of
Independent Registered Public Accounting Firm
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100
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Management's
Discussion and Analysis of Results of Operations and
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101-114
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Financial
Condition
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The
Toledo Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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115
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Consolidated
Balance Sheets
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116
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Consolidated
Statements of Cash Flows
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117
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Report
of
Independent Registered Public Accounting Firm
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118
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Management's
Discussion and Analysis of Results of Operations and
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119-131
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Financial
Condition
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Pennsylvania
Power Company
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Consolidated
Statements of
Income
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132
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Consolidated
Balance
Sheets
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133
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Consolidated
Statements of
Cash Flows
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134
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Report
of
Independent Registered Public Accounting Firm
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135
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Management's
Discussion and Analysis of Results of Operations and
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136-144
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Financial
Condition
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TABLE
OF
CONTENTS (Cont'd)
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Pages
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Jersey
Central Power & Light Company
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Consolidated
Statements of Income and Comprehensive Income
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145
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Consolidated
Balance Sheets
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146
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Consolidated
Statements of Cash Flows
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147
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Report
of
Independent Registered Public Accounting Firm
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148
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Management's
Discussion and Analysis of Results of Operations and
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149-159
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Financial
Condition
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Metropolitan
Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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160
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Consolidated
Balance Sheets
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161
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Consolidated
Statements of Cash Flows
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162
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Report
of
Independent Registered Public Accounting Firm
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163
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Management's
Discussion and Analysis of Results of Operations and
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164-174
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Financial
Condition
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Pennsylvania
Electric Company
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Consolidated
Statements of Income and Comprehensive Income
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175
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Consolidated
Balance Sheets
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176
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Consolidated
Statements of Cash Flows
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177
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Report
of
Independent Registered Public Accounting Firm
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178
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Management's
Discussion and Analysis of Results of Operations and
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179-189
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Financial
Condition
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk.
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190
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Item
4. Controls
and Procedures.
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190
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Part
II. Other
Information
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Item
1. Legal
Proceedings.
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191
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Item
1A. Risk
Factors.
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191
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Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds.
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191
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Item
6. Exhibits.
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192-193
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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
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American
Transmission Systems, Inc., owns and operates transmission
facilities
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CEI
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The
Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
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Centerior
|
Centerior
Energy Corporation, former parent of CEI and TE, which merged
with OE to
form
FirstEnergy
on
November 8, 1997
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CFC
|
Centerior
Funding Corporation, a wholly owned finance subsidiary of
CEI
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Companies
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OE,
CEI, TE,
Penn, JCP&L, Met-Ed and Penelec
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FENOC
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FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
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FES
|
FirstEnergy
Solutions Corp., provides energy-related products and
services
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FESC
|
FirstEnergy
Service Company, provides legal, financial, and other corporate
support
services
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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
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FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
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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 Funding
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JCP&L
Transition Funding LLC, a Delaware limited liability company
and issuer of
transition bonds
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JCP&L
Transition Funding II
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JCP&L
Transition Funding II LLC, a Delaware limited liability company
and issuer
of transition bonds
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Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
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MYR
|
MYR
Group,
Inc., a utility infrastructure construction service
company
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NGC
|
FirstEnergy
Nuclear Generation Corp., owns nuclear generating
facilities
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OE
|
Ohio
Edison
Company, an Ohio electric utility operating subsidiary
|
OE
Companies
|
OE
and
Penn
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Ohio
Companies
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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
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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
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TE
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The
Toledo
Edison Company, an Ohio electric utility operating
subsidiary
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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
No. 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
|
B&W
|
Babcock
&
Wilcox Company
|
Bechtel
|
Bechtel
Power
Corporation
|
BGS
|
Basic
Generation Service
|
BTU
|
British
Thermal Unit
|
CAIDI
|
Customer
Average Interruption Duration Index
|
CAIR
|
Clean
Air
Interstate Rule
|
CAL
|
Confirmatory
Action Letter
|
CAMR
|
Clean
Air
Mercury Rule
|
CBP
|
Competitive
Bid Process
|
CIEP
|
Commercial
Industrial Energy Price
|
CO2
|
Carbon
Dioxide
|
CTC
|
Competitive
Transition Charge
|
DCPD
|
Deferred
Compensation Plan for Outside Directors
|
DIG
C20
|
Derivatives
Implementation Group Issue No. C20, “Scope Exceptions: Interpretations of
the
Meaning
of Not
Clearly and Closely Related in Paragraph 10(b) regarding Contracts
with a
Price
Adjustment Feature”
|
GLOSSARY
OF
TERMS Cont’d.
DOJ
|
U.S.
Department of Justice
|
DRA
|
Division
of
the Ratepayer Advocate
|
ECAR
|
East
Central
Area Reliability Coordination Agreement
|
EDCP
|
Executive
Deferred Compensation Plan
|
EITF
|
Emerging
Issues Task Force
|
EPA
|
U.S.
Environmental Protection Agency
|
EPACT
|
Energy
Policy
Act of 2005
|
ERO
|
Electric
Reliability Organization
|
ESOP
|
Employee
Stock
Ownership Plan
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
U.S.
Federal
Energy Regulatory Commission
|
FIN
|
FASB
Interpretation
|
FIN
46(R)
|
FIN
46
(revised December 2003), "Consolidation of Variable Interest
Entities"
|
FIN
46(R)-6
|
FIN
46(R)-6,
“Determining the Variability to be Considered in Applying FASB
interpretation No. 46(R)”
|
FIN
47
|
FIN
47,
"Accounting for Conditional Asset Retirement Obligations - an
interpretation of FASB
Statement
No.
143"
|
FIN
48
|
FIN
48,
“Accounting for Uncertainty in Income Taxes - an interpretation
of FASB
Statement No.109”
|
FMB
|
First
Mortgage
Bonds
|
FSP
|
FASB
Staff
Position
|
FSP
FIN
13-2
|
FSP
FIN 13-2,
“Accounting for a Change or Projected Change in the Timing of
Cash Flows
Relating
to
Income
Taxes Generated by a Leveraged Lease Transaction”
|
GAAP
|
Accounting
Principles Generally Accepted in the United States
|
GCAF
|
Generation
Charge Adjustment Factor
|
GHG
|
Greenhouse
Gases
|
KWH
|
Kilowatt-hours
|
LOC
|
Letter
of
Credit
|
LTIP
|
Long-Term
Incentive Program
|
MEIUG
|
Met-Ed
Industrial Users Group
|
MISO
|
Midwest
Independent Transmission System Operator, Inc.
|
Moody’s
|
Moody’s
Investors Service
|
MOU
|
Memorandum
of
Understanding
|
MSG |
Market
Support Generation |
MTC
|
Market
Transition Charge
|
MW
|
Megawatts
|
MWH
|
Megawatt-hours
|
NAAQS
|
National
Ambient Air Quality Standards
|
NERC
|
North
American
Electric Reliability Council
|
NJBPU
|
New
Jersey
Board of Public Utilities
|
NOAC
|
Northwest
Ohio
Aggregation Coalition
|
NOPR
|
Notice
of
Proposed Rulemaking
|
NOV
|
Notices
of
Violation
|
NOX
|
Nitrogen
Oxide
|
NRC
|
U.S.
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
|
PaDEP
|
Pennsylvania
Department of Environmental Protection
|
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
|
GLOSSARY
OF
TERMS Cont’d.
RTC |
Regulatory
Transition Charge |
RTO
|
Regional
Transmission Organization
|
RTOR
|
Regional
Through and Out Rates
|
S&P
|
Standard
&
Poor’s Ratings Service
|
SAB
108
|
SEC
Staff
Accounting Bulletin No. 108, “Considering the Effects of Prior Year
Misstatements when
Quantifying
Misstatements in Current Year Financial Statements”
|
SAIFI
|
System
Average
Interruption Frequency Index
|
SBC
|
Societal
Benefits Charge
|
SEC
|
U.S.
Securities and Exchange Commission
|
SECA
|
Seams
Elimination Cost Adjustment
|
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
142
|
SFAS
No. 142,
“Goodwill and Other Intangible Assets”
|
SFAS
143
|
SFAS
No. 143,
"Accounting for Asset Retirement Obligations"
|
SFAS
144
|
SFAS
No. 144,
"Accounting for the Impairment or Disposal of Long-Lived
Assets"
|
SFAS
157
|
SFAS
No. 157,
“Fair Value Measurements”
|
SFAS
158
|
SFAS
No. 158,
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement
Plans-an
amendment of FASB Statements No. 87, 88, 106, and
132(R)”
|
SIP |
State
Implementation Plan(s) Under the Clean Air Act |
SO2
|
Sulfur
Dioxide
|
SRM
|
Special
Reliability Master
|
TBC
|
Transition
Bond Charge
|
TMI-2
|
Three
Mile
Island Unit 2
|
VIE
|
Variable
Interest Entity
|
VMEP
|
Vegetation
Management Enhancement Project
|
PART
I.
FINANCIAL INFORMATION
FIRSTENERGY
CORP. AND SUBSIDIARIES
OHIO
EDISON
COMPANY AND SUBSIDIARIES
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE
TOLEDO
EDISON COMPANY AND SUBSIDIARY
PENNSYLVANIA
POWER COMPANY AND SUBSIDIARY
JERSEY
CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN
EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA
ELECTRIC COMPANY AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1.
-
ORGANIZATION AND BASIS OF PRESENTATION
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 nine months ended September 30, 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.
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.
On
August 10, 2006, FirstEnergy repurchased 10.6 million shares,
approximately 3.2%, of its outstanding common stock through an accelerated
share
repurchase program (see Note 10(D)). The initial purchase price was
$600 million, or $56.44 per share. The final purchase price will be
adjusted to reflect the ultimate cost to acquire the shares over a period
of up
to seven months. The
2006 basic and
diluted earnings per share results reflect the impact associated with the
August
2006 accelerated share repurchase program. FirstEnergy intends to settle,
in
shares or cash, any obligation on its part to pay the difference between
the
average of the daily volume-weighted average price of the shares as calculated
under the program and the initial price of the shares. Since the effect of
any
potential settlement in shares is currently unknown and therefore not expected
to be dilutive, there is no impact on reported diluted earnings per share.
The
following table reconciles the computation of basic and diluted earnings
per
share of common stock before discontinued operations:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Basic and Diluted Earnings per Share
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions, except per share amounts)
|
|
Income
Before
Discontinued Operations
|
|
$
|
454
|
|
$
|
332
|
|
$
|
979
|
|
$
|
652
|
|
Less:
Redemption premium on subsidiary preferred stock
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
|
-
|
|
Earnings
on
Common Stock Before Discontinued Operations
|
|
$
|
454
|
|
$
|
332
|
|
$
|
976
|
|
$
|
652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares of Common Stock Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for basic earnings per share
|
|
|
322
|
|
|
328
|
|
|
326
|
|
|
328
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
3
|
|
|
2
|
|
|
3
|
|
|
2
|
|
Denominator
for diluted earnings per share
|
|
|
325
|
|
|
330
|
|
|
329
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Before Discontinued Operations per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$1.41
|
|
|
$1.01
|
|
|
$2.99
|
|
|
$1.99
|
|
Diluted
|
|
|
$1.40
|
|
|
$1.01
|
|
|
$2.97
|
|
|
$1.98
|
|
3.
-
GOODWILL
In
a business
combination, the excess of the purchase price over the estimated fair values
of
assets acquired and liabilities assumed is recognized as goodwill. Based
on the
guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment
at least annually and more frequently as indicators of impairment arise.
In
accordance with the accounting standard, if the fair value of a reporting
unit
is less than its carrying value (including goodwill), the goodwill is tested
for
impairment. If impairment is indicated, FirstEnergy recognizes a loss -
calculated as the difference between the implied fair value of a reporting
unit's goodwill and the carrying value of the goodwill.
FirstEnergy's
2006
annual review was completed in the third quarter of 2006 with no impairment
indicated. As discussed in Note 11 to the consolidated financial statements,
Met-Ed and Penelec have rate increase requests pending before the PPUC. The
annual goodwill impairment analysis assumed management's best estimate of
the
rate increases that are expected to be granted in January 2007. If the PPUC
authorizes less than the amounts assumed, an additional impairment analysis
would be performed at that time and this could result in a future goodwill
impairment loss that could be material. If rate relief were completely denied,
it is estimated that approximately $604 million of Met-Ed’s goodwill would
be impaired and approximately $374 million of Penelec’s goodwill would be
impaired, and those amounts would be written off by those companies. However,
no
adjustment to FirstEnergy’s goodwill on a consolidated basis would be recognized
in that circumstance because the fair value of its regulated segment (which
represents FirstEnergy's reporting unit to evaluate goodwill) would continue
to
exceed the carrying value of its investment in the segment.
FirstEnergy's
goodwill primarily relates to its regulated services segment. In the nine
months
ended September 30, 2006, FirstEnergy adjusted goodwill related to the
divestiture of a non-core asset (62% interest in MYR), a successful tax claim
relating to the former Centerior companies, and adjustments to the former
GPU
companies due to the realization of tax benefits that had been reserved in
purchase accounting. The following tables reconcile
changes to goodwill
for the three months and nine months ended September 30,
2006.
Three
Months Ended
|
|
FirstEnergy
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance
as of
July 1, 2006
|
|
$
|
5,940
|
|
$
|
1,688
|
|
$
|
501
|
|
$
|
1,978
|
|
$
|
860
|
|
$
|
878
|
|
Adjustments
related to GPU acquisition
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
(4
|
)
|
Balance
as of
September 30, 2006
|
|
$
|
5,935
|
|
$
|
1,688
|
|
$
|
501
|
|
$
|
1,977
|
|
$
|
860
|
|
$
|
874
|
|
Nine
Months Ended
|
|
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
|
|
|
(21
|
)
|
|
|
|
|
|
|
|
(9
|
)
|
|
(4
|
)
|
|
(8
|
)
|
Balance
as of
September 30, 2006
|
|
$
|
5,935
|
|
$
|
1,688
|
|
$
|
501
|
|
$
|
1,977
|
|
$
|
860
|
|
$
|
874
|
|
4.
-
DIVESTITURES AND DISCONTINUED OPERATIONS
In
August 2006,
FirstEnergy sold two FSG subsidiaries (Roth Bros. and Hattenbach) for a net
after-tax gain of $1.9 million. The remaining FSG subsidiaries continue to
be actively marketed and qualify as assets held for sale in accordance with
SFAS 144 because FirstEnergy anticipates that the transfer of these assets,
with a net carrying value of $30.6 million as of September 30, 2006,
will qualify for recognition as completed sales within one year. As of
September 30, 2006, the remaining FSG subsidiaries classified as held for
sale did not meet the criteria for discontinued operations. The carrying
amounts
of FSG's assets and liabilities are not material and have not been presented
separately as assets held for sale on FirstEnergy's Consolidated Balance
Sheets.
See Note 13 for FSG's segment financial information.
In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax
gain
of $0.2 million. In June 2006, FirstEnergy sold an additional 1.67% interest.
As
a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter
of 2006 and accounts for its remaining 38.33% interest under the equity
method.
In March 2005, 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.
During the first nine months of 2005, FirstEnergy sold three FSG subsidiaries
(Cranston, Elliott-Lewis and Spectrum), an MYR subsidiary (Power Piping)
and
FES' retail natural gas business, resulting in aggregate after-tax gains
of
$17 million.
Net
results
(including the gains on sales of assets discussed above) for Cranston,
Elliott-Lewis, Power Piping and FES' retail natural gas business of
$18 million for the nine months ended September 30, 2005 are reported
as discontinued operations on FirstEnergy's Consolidated Statements of Income.
Pre-tax operating results for these entities were $2 million for the nine
months ended September 30, 2005. Revenues associated with discontinued
operations for the nine months ended September 30, 2005 were
$207 million. The following table summarizes the sources of income from
discontinued operations (in millions) for the nine months ended
September 30, 2005:
Discontinued
Operations (Net of tax)
|
|
|
|
Gain
on
sale:
|
|
|
|
Natural
gas
business
|
|
$
|
5
|
FSG
and MYR
subsidiaries
|
|
|
12
|
Reclassification
of operating income
|
|
|
1
|
Total
|
|
$
|
18
|
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. The Committee is responsible
for promoting the effective design and implementation of sound risk management
programs and oversees 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
exception criterion. 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 criterion 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 $48 million included in AOCL as of September 30,
2006, for derivative hedging activity, as compared to the December 31, 2005
balance of $78 million of net deferred losses, resulted from a net
$13 million decrease related to current hedging activity and a
$17 million decrease due to net hedge losses reclassified into earnings
during the nine months ended September 30, 2006. Based on current estimates,
approximately $15 million (after tax) of the net deferred losses on
derivative instruments in AOCL as of September 30, 2006 is expected to be
reclassified to earnings during the next twelve months as hedged transactions
occur. The fair value of these derivative instruments 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 nine months ended September 30, 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
September 30, 2006, FirstEnergy had interest rate swaps with an aggregate
notional value of $750 million and a fair value of
($29) million.
During 2005 and the first nine months 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 subsidiaries
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. FirstEnergy revised the
tenor
and timing of its financing plan during the first nine months of 2006.
FirstEnergy terminated and revised forward swaps with an aggregate notional
value of $600 million during the second quarter of 2006, ultimately
terminating the swaps as its subsidiaries issued long-term debt. In the third
quarter of 2006, FirstEnergy revised the timing of swaps with an aggregate
notional value of $100 million. As required by SFAS 133, FirstEnergy
assessed the amount of ineffectiveness of the hedges at each termination.
FirstEnergy received cash gains of $43 million, of which approximately
$6 million ($4 million net of tax) was deemed ineffective and
recognized in earnings in the first nine months of 2006. The remaining gain
deemed effective in the amount of approximately $38 million
($23 million net of tax) was recorded in other comprehensive income and
will subsequently be recognized in earnings over the terms of the associated
future debt. As of September 30, 2006, FirstEnergy had forward swaps with
an
aggregate notional amount of $725 million and a long-term debt securities
fair value of ($2) million.
6.
- STOCK
BASED COMPENSATION
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 three months and nine months ended
September 30, 2006 included the expense for all share-based payments
granted prior to but not yet vested as of January 1, 2006. Results for
prior periods were not restated.
Prior to the adoption of SFAS 123(R) on January, 1, 2006, FirstEnergy’s LTIP,
EDCP, ESOP, and DCPD stock-based compensation programs were 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.
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), compensation 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 granted
since
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 three
months and nine months ended September 30, 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. Reference
is
made to FirstEnergy’s annual report on Form 10-K for the year ended December 31,
2005 for expanded annual disclosure.
The following table illustrates the effect on net income and earnings per
share
for the three months and nine months ended September 30, 2005, as if
FirstEnergy had adopted SFAS 123(R) as of January 1, 2005:
|
|
Three
Months
|
|
Nine
Months
|
|
|
|
(In
millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
Net
Income, as
reported
|
|
$
|
332
|
|
$
|
670
|
|
|
|
|
|
|
|
|
|
Add
back
compensation expense
|
|
|
|
|
|
|
|
reported
in
net income, net of tax (based on
|
|
|
|
|
|
|
|
APB
25)*
|
|
|
17
|
|
|
40
|
|
|
|
|
|
|
|
|
|
Deduct
compensation expense based
|
|
|
|
|
|
|
|
upon
estimated
fair value, net of tax*
|
|
|
(19
|
)
|
|
(47
|
)
|
|
|
|
|
|
|
|
|
Pro
forma net
income
|
|
$
|
330
|
|
$
|
663
|
|
Earnings
Per
Share of Common Stock -
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
As
Reported
|
|
|
$1.01
|
|
|
$2.04
|
|
Pro
Forma
|
|
|
$1.01
|
|
|
$2.02
|
|
Diluted
|
|
|
|
|
|
|
|
As
Reported
|
|
|
$1.01
|
|
|
$2.03
|
|
Pro
Forma
|
|
|
$1.00
|
|
|
$2.01
|
|
* 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 nine months ended September 30, 2005, the impact on earnings
would have been immaterial.
The
ARO liability of
$1.2 billion as of September 30, 2006 primarily relates 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
uses 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
September 30, 2006, the fair value of the decommissioning trust assets was
$1.9 billion.
The
following tables
analyze changes to the ARO balances during the three months and nine months
ended September 30, 2006 and 2005, respectively.
Three
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
Penn
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
July
1, 2006
|
|
$
|
1,160
|
|
$
|
85
|
|
$
|
2
|
|
$
|
26
|
|
$
|
-
|
|
$
|
82
|
|
$
|
146
|
|
$
|
74
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
19
|
|
|
2
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
3
|
|
|
2
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2006
|
|
$
|
1,179
|
|
$
|
87
|
|
$
|
2
|
|
$
|
26
|
|
$
|
-
|
|
$
|
83
|
|
$
|
149
|
|
$
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
July
1, 2005
|
|
$
|
1,113
|
|
$
|
208
|
|
$
|
281
|
|
$
|
201
|
|
$
|
143
|
|
$
|
75
|
|
$
|
137
|
|
$
|
68
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
3
|
|
|
5
|
|
|
4
|
|
|
2
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
11
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2005
|
|
$
|
1,130
|
|
$
|
209
|
|
$
|
281
|
|
$
|
200
|
|
$
|
156
|
|
$
|
76
|
|
$
|
139
|
|
$
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
Penn
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2006
|
|
$
|
1,126
|
|
$
|
83
|
|
$
|
8
|
|
$
|
25
|
|
$
|
-
|
|
$
|
80
|
|
$
|
142
|
|
$
|
72
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
(6
|
)
|
|
-
|
|
|
(6
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
55
|
|
|
4
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
3
|
|
|
7
|
|
|
4
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2006
|
|
$
|
1,179
|
|
$
|
87
|
|
$
|
2
|
|
$
|
26
|
|
$
|
-
|
|
$
|
83
|
|
$
|
149
|
|
$
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2005
|
|
$
|
1,078
|
|
$
|
201
|
|
$
|
272
|
|
$
|
195
|
|
$
|
138
|
|
$
|
72
|
|
$
|
133
|
|
$
|
67
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
53
|
|
|
10
|
|
|
14
|
|
|
10
|
|
|
7
|
|
|
4
|
|
|
6
|
|
|
2
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
11
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2005
|
|
$
|
1,130
|
|
$
|
209
|
|
$
|
281
|
|
$
|
200
|
|
$
|
156
|
|
$
|
76
|
|
$
|
139
|
|
$
|
69
|
|
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 pension benefits and other postretirement benefits
from the time employees are hired until they become eligible to receive those
benefits.
The
components of
FirstEnergy's net periodic pension and other postretirement benefit costs
(including amounts capitalized) for the three months and nine months ended
September 30, 2006 and 2005 consisted of the following:
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Pension
Benefits
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
21
|
|
$
|
19
|
|
$
|
63
|
|
$
|
58
|
|
Interest
cost
|
|
|
66
|
|
|
64
|
|
|
199
|
|
|
191
|
|
Expected
return on plan assets
|
|
|
(99
|
)
|
|
(86
|
)
|
|
(297
|
)
|
|
(259
|
)
|
Amortization
of prior service cost
|
|
|
2
|
|
|
2
|
|
|
7
|
|
|
6
|
|
Recognized
net
actuarial loss
|
|
|
15
|
|
|
9
|
|
|
44
|
|
|
27
|
|
Net
periodic
cost
|
|
$
|
5
|
|
$
|
8
|
|
$
|
16
|
|
$
|
23
|
|
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Other
Postretirement Benefits
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
9
|
|
$
|
10
|
|
$
|
26
|
|
$
|
30
|
|
Interest
cost
|
|
|
26
|
|
|
27
|
|
|
79
|
|
|
83
|
|
Expected
return on plan assets
|
|
|
(12
|
)
|
|
(11
|
)
|
|
(35
|
)
|
|
(34
|
)
|
Amortization
of prior service cost
|
|
|
(19
|
)
|
|
(11
|
)
|
|
(57
|
)
|
|
(33
|
)
|
Recognized
net
actuarial loss
|
|
|
14
|
|
|
10
|
|
|
42
|
|
|
30
|
|
Net
periodic
cost
|
|
$
|
18
|
|
$
|
25
|
|
$
|
55
|
|
$
|
76
|
|
Pension and postretirement benefit obligations are allocated to FirstEnergy’s
subsidiaries employing the plan participants. FirstEnergy’s subsidiaries
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
and nine months ended September 30, 2006 and 2005 were as
follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Pension
Benefit Cost (Credit)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
(1.1
|
)
|
$
|
0.2
|
|
$
|
(3.3
|
)
|
$
|
0.7
|
|
Penn
|
|
|
(0.4
|
)
|
|
(0.2
|
)
|
|
(1.2
|
)
|
|
(0.7
|
)
|
CEI
|
|
|
1.0
|
|
|
0.3
|
|
|
2.9
|
|
|
1.0
|
|
TE
|
|
|
0.2
|
|
|
0.3
|
|
|
0.7
|
|
|
1.0
|
|
JCP&L
|
|
|
(1.4
|
)
|
|
(0.3
|
)
|
|
(4.1
|
)
|
|
(0.8
|
)
|
Met-Ed
|
|
|
(1.7
|
)
|
|
(1.1
|
)
|
|
(5.2
|
)
|
|
(3.2
|
)
|
Penelec
|
|
|
(1.3
|
)
|
|
(1.3
|
)
|
|
(4.0
|
)
|
|
(4.0
|
)
|
Other
FirstEnergy subsidiaries
|
|
|
9.9
|
|
|
9.6
|
|
|
29.9
|
|
|
28.6
|
|
|
|
$
|
5.2
|
|
$
|
7.5
|
|
$
|
15.7
|
|
$
|
22.6
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Other
Postretirement Benefit Cost
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
3.4
|
|
$
|
5.8
|
|
$
|
10.2
|
|
$
|
17.3
|
|
Penn
|
|
|
0.8
|
|
|
1.2
|
|
|
2.4
|
|
|
3.5
|
|
CEI
|
|
|
2.8
|
|
|
3.8
|
|
|
8.3
|
|
|
11.4
|
|
TE
|
|
|
2.0
|
|
|
2.2
|
|
|
6.1
|
|
|
6.5
|
|
JCP&L
|
|
|
0.6
|
|
|
1.5
|
|
|
1.8
|
|
|
5.7
|
|
Met-Ed
|
|
|
0.7
|
|
|
0.4
|
|
|
2.2
|
|
|
1.2
|
|
Penelec
|
|
|
1.8
|
|
|
2.0
|
|
|
5.4
|
|
|
5.9
|
|
Other
FirstEnergy subsidiaries
|
|
|
6.1
|
|
|
8.0
|
|
|
18.1
|
|
|
24.5
|
|
|
|
$
|
18.2
|
|
$
|
24.9
|
|
$
|
54.5
|
|
$
|
76.0
|
|
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 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-leaseback
agreements, OE, CEI and TE have net minimum discounted lease payments of
$655 million, $95 million and $506 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.
FirstEnergy expects any above-market costs it incurs to be recovered from
customers. As of September 30, 2006, the net above-market loss liability
projected for these eight NUG agreements was $239 million. Purchased power
costs from these entities during the three months and nine months ended
September 30, 2006 and 2005 are shown in the following table:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
JCP&L
|
|
$
|
29
|
|
$
|
33
|
|
$
|
63
|
|
$
|
74
|
|
Met-Ed
|
|
|
12
|
|
|
10
|
|
|
45
|
|
|
40
|
|
Penelec
|
|
|
8
|
|
|
7
|
|
|
22
|
|
|
21
|
|
Total
|
|
$
|
49
|
|
$
|
50
|
|
$
|
130
|
|
$
|
135
|
|
Securitized
Transition Bonds
The
consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned
limited liability companies of JCP&L. In June 2002, JCP&L Transition
Funding 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. In August 2006, JCP&L Transition
Funding II sold $182 million of transition bonds to securitize the recovery
of
deferred costs associated with JCP&L’s supply of BGS.
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 the sole obligations of JCP&L Transition Funding and
JCP&L Transition Funding II and are collateralized by each company’s equity
and assets, which consists primarily of bondable transition property.
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 transition bonds
and
other fees and expenses associated with their issuance. JCP&L sold its
bondable transition property to JCP&L Transition Funding and JCP&L
Transition Funding II and, as servicer, manages and administers the bondable
transition property, including the billing, collection and remittance of
the
TBC, pursuant to separate servicing agreements with JCP&L Transition Funding
and JCP&L Transition Funding II. For the two series of transition bonds,
JCP&L is entitled to aggregate quarterly servicing fees of $157,000 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 September 30, 2006, outstanding guarantees and
other assurances totaled approximately $3.6 billion consisting of contract
guarantees $2.0 billion, surety bonds $0.2 billion and LOCs
$1.4 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 credit support
for
subsidiary financings or refinancings of costs related to the acquisition
of, or
improvements to, 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 $2.0 billion discussed
above) as of September 30, 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
September 30, 2006, FirstEnergy's maximum exposure under these collateral
provisions was $487 million.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of
$147 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
September 30, 2006), which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA. The LOC was reduced to $27 million on
October 15, 2006.
(B) ENVIRONMENTAL
MATTERS
Various federal, state and local authorities regulate FirstEnergy 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.
FirstEnergy accrues environmental liabilities only 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 FirstEnergy’s
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
emissions
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
believes it is currently in compliance with this policy, but cannot predict
what
action the EPA may take in the future with respect to the interim enforcement
policy.
The EPA
Region
5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated
June
15, 2006 alleging violations to various sections of the Clean Air Act. A
meeting
was held on August 8, 2006 to discuss the alleged violations with the EPA.
FirstEnergy has disputed those alleged violations based on its Clean Air
Act
permit, the Ohio SIP and other information provided at the August 2006 meeting
with the EPA. The EPA has several enforcement options (administrative compliance
order, administrative penalty order, and/or judicial, civil or criminal action)
and has indicated that such option may depend on the time needed to achieve
and
demonstrate compliance with the rules alleged to have been
violated.
FirstEnergy complies 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 at
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 SIPs 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 fine
particulate matter. In March 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 facility 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. In
March
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 then,
new
and non-emitting generating facilities, including renewables and nuclear,
would
be entitled to their proportionate share of the allowances. Consequently,
FirstEnergy will be disadvantaged if these model rules were implemented as
proposed because FirstEnergy’s substantial reliance on non-emitting (largely
nuclear) generation is not recognized under the input-based
allocation.
Pennsylvania has proposed a new rule to regulate mercury emissions from
coal-fired power plants that does not provide a cap and trade approach as
in
CAMR, but rather follows a command and control approach imposing emission
limits
on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation
would deprive FirstEnergy of mercury emission allowances that were to be
allocated to the Bruce Mansfield Plant under CAMR and that would otherwise
be
available for achieving FirstEnergy system-wide compliance. The future cost
of
compliance with these regulations, if adopted and implemented as proposed,
may
be substantial.
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 ($400 million of which is expected to be spent in 2007 with
the
primary portion of the remaining $1.1 billion expected to be spent in 2008
and
2009). On August 26, 2005, FGCO entered into an agreement with Bechtel
Power
Corporation under which Bechtel will engineer, procure, and construct air
quality control systems for the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement
with
B&W.
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 KWH
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
September 30, 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 $73 million (JCP&L -
$55 million,
CEI -
$1 million,
and other subsidiaries-
$17 million)
have been accrued through September 30, 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. In 2005, JCP&L renewed its motion to decertify the
class based on a very limited number of class members who incurred damages
and
also filed a motion for summary judgment on the remaining plaintiffs’ claims for
negligence, breach of contract and punitive damages. In July 2006, the New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did
not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division because it effectively terminates this class action. Briefs are
being
prepared and filed, and legal argument is scheduled for late November 2006.
FirstEnergy is unable to predict the outcome of these matters and no liability
has been accrued as of September 30, 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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
FirstEnergy companies also are defending six separate complaint cases before
the
PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of
their
insured. In each of these three 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 sixth case involves the claim of a non-customer
seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003. That case has been dismissed. On
March 7,
2006, the PUCO issued a ruling, based on motions filed by the parties,
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 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.
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
that provide their service. The PUCO denied all other motions for rehearing.
The
plaintiffs in each case have since filed an amended complaint and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have
been
set for hearing on October 16, 2007.
On October 10, 2006, various insurance carriers refiled a complaint in
Cuyahoga
County Common Pleas Court seeking reimbursement for claims paid to numerous
insureds who allegedly suffered losses as a result of the August 14, 2003
outages. All of the insureds appear to be non-customers. The plaintiff
insurance
companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
the
Ohio Companies and Penn were served on October 27, 2006, and expect to seek
summary dismissal of these cases based on the prior court rulings noted
above.
No estimate of potential liability is available for any of these
cases.
FirstEnergy was also named, along with several other entities, in a complaint
in
New Jersey State Court. The allegations against FirstEnergy were based, in
part,
on an alleged failure to protect the citizens of Jersey City from an electrical
power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City.
A responsive pleading has been filed. On April 28, 2006, the Court granted
FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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 had 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
(not deductible for income tax purposes) which reduced FirstEnergy'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.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Nuclear Power 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 the Perry Nuclear Power
Plant
on March 14, 2006, the NRC again stated that the Perry Nuclear Power 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
the
now repealed 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. On October 18, 2006, the Ohio Supreme Court transferred this
case to a Tuscarawas County Common Pleas Court judge due to concerns over
potential class membership by the Jefferson County Common Pleas
Court.
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 arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss as premature
a
JCP&L appeal of the award filed on October 18, 2005. JCP&L intends
to re-file an 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. Both filings
were
consolidated for hearing and decision. 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.
On
May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
complaint and approving the related tariffs, thus affirming OE’s entitlement to
recovery of its transition charges.
The City of Huron
filed an application for rehearing of the PUCO’s decision on June 9, 2006
and OE filed a memorandum in opposition to that application on June 19,
2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
City of Huron has taken no further action and the period for filing an appeal
has expired.
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.
(D) ACCELERATED
SHARE REPURCHASE PROGRAM
On August 9, 2006, FirstEnergy entered into an accelerated share repurchase
agreement with a financial institution counterparty under which FirstEnergy
repurchased 10.6 million shares, or approximately 3.2%, of its outstanding
common stock on August 10, 2006 at an initial price of $56.44 per share,
or a
total initial purchase price of $600 million. This forward sale contract
is
being accounted for as an equity instrument. The final purchase price is
subject
to a contingent purchase price adjustment based on the average of the daily
volume-weighted average prices over a subsequent purchase period of up to
seven
months, as well as other purchase price adjustments in the event of an
extraordinary cash dividend or other dilution events. The price adjustment
can
be settled, at FirstEnergy’s option, in cash or in shares of its common stock.
The size of any settlement amount and whether it is to be paid or received
by
FirstEnergy will depend upon the average of the daily volume-weighted average
prices of the shares as calculated by the counterparty under the program.
The
settlement is expected to occur in the first quarter of 2007.
The
accelerated
share repurchase was completed under a program authorized by the Board of
Directors on June 20, 2006 to repurchase up to 12 million shares of
common stock. At management’s discretion, additional shares may be acquired
under the program on the open market or through privately negotiated
transactions, subject to market conditions and other factors. The Board’s
authorization of the repurchase program does not require FirstEnergy to make
any
further repurchases of shares and the program may be terminated at any
time.
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 equipment 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,
all
of which could require additional, material expenditures.
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 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 an SRM 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. The SRM completed his work and issued his
final report to the NJBPU on June 1, 2006. A meeting was held between JCP&L
and the NJBPU on June 29, 2006 to discuss the SRM’s final report. JCP&L
filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L
continues to file compliance reports reflecting activities associated with
the
MOU and Stipulation.
The EPACT provides for the creation of an ERO to establish and enforce
reliability standards for the bulk power system, subject to FERC’s 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
reliability organizations (regional entities). The new FERC rule referred
to
above, further provides for reorganizing regional entities that would replace
the current regional councils and for rearranging their 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. The ERO filing was noticed on April 7, 2006 and comments
and reply comments were filed in May, June and July 2006. On July 20, 2006,
the
FERC certified the NERC as the ERO to implement the provisions of Section
215 of
the Federal Power Act and directed the NERC to make a compliance filing within
90 days addressing such issues as the regional delegation agreements. The
NERC
made its compliance filing in October 2006. This filing is pending before
the
FERC.
On
April 4, 2006,
NERC also submitted a filing with the FERC seeking approval of mandatory
reliability standards. These reliability standards are based, with some
modifications and additions, on the current NERC Version O reliability
standards. The reliability standards filing was noticed by the FERC on
April 18,
2006. In that notice, the FERC announced its intent to issue a Notice
of
Proposed Rulemaking on the proposed reliability standards at a future
date. On
May 11, 2006, the FERC staff released a preliminary assessment that cited
many deficiencies in the proposed reliability standards. The NERC and
industry
participants filed comments in response to the Staff’s preliminary assessment.
The FERC held a technical conference on the proposed reliability standards
on
July 6, 2006. The FERC issued a Notice of Proposed Rulemaking on the
proposed
reliability standards on October 20, 2006. The FERC voted to adopt 83 of
the proposed 107 reliability standards. The FERC asked the NERC to make
technical improvements to 62 of the 83 standards approved. The 24 standards
that
were not adopted remain pending at the FERC awaiting further clarification
and
filings by the NERC and regional entities. The FERC also provided additional
clarification on the proposed application of final standards in the NOPR.
Interested parties will be given the opportunity to comment on the NOPR
within
60 days of its publication in the Federal Register. Mandatory reliability
standards are expected to be in place by the summer of 2007. In a separate
order
issued October 24, 2006, the FERC approved NERC’s 2007 budget and business
plan subject to certain compliance filings.
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.
On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security
standards that replaced interim standards put in place in the wake of the
September 11, 2001 terrorist attacks, and thirteen additional reliability
standards. The security standards became effective on June 1, 2006, and the
remaining standards will become effective throughout 2006 and 2007. NERC
intends
to file the standards with the FERC and relevant Canadian authorities for
approval, but
the cyber security standards were not included in the October 20, 2006
NOPR.
FirstEnergy
believes
it is in compliance with all current NERC reliability standards.
However, based
upon a review
of the October 20, 2006 NOPR, it appears 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.
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.
OHIO
On
October 21, 2003,
the Ohio Companies filed their 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 the
PUCO’s 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 the proceeding as well as the associated entries
on
rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
the PUCO's order with respect to the approval of the rate stabilization charge,
approval of the shopping credits, the granting of interest on shopping credit
incentive deferral amounts, and approval of the Ohio Companies’ financial
separation plan. It remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the competitive
marketplace. The RSP contained a provision that permitted the Ohio Companies
to
withdraw and terminate the RSP in the event that the PUCO, or the Supreme
Court
of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
have
30 days from the final order or decision to provide notice of termination.
On
July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
a
Proceeding on Remand. In their Request, the Ohio Companies provided notice
of
termination to those provisions of the RSP subject to termination, subject
to
being withdrawn, and also set forth a framework for addressing the Supreme
Court
of Ohio’s findings on customer participation, requesting the PUCO to initiate a
proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
resolution to the issues raised by the Supreme Court of Ohio that is acceptable
to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
considered to be null and void. Separately, the OCC and NOAC also submitted
to
the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
by
the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC
and
NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
to
address the Court’s concern. On September 19, 2006, the PUCO issued an
Entry granting the Ohio Companies’ motion for extension of time to file the
remand proposal. The Ohio Companies filed their RSP Remand CBP on
September 29, 2006. No further proceedings have been scheduled at this
time.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
November 4, 2005, the Ohio Companies filed a supplemental stipulation with
the
PUCO, which constituted an additional component of the RCP filed on September
9,
2005. Major provisions of the RCP include:
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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;
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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;
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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
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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.
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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. 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:
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Recognize
fuel
and distribution deferrals commencing January 1,
2006;
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Recognize
distribution deferrals on a monthly basis prior to review by the
PUCO
Staff;
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Clarify
that
the types of distribution expenditures included in the Supplemental
Stipulation may be deferred; and
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Clarify
that
distribution expenditures do not have to be “accelerated” in order to be
deferred.
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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 8, 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 notices of appeal with the
Supreme Court of Ohio alleging various errors made by the PUCO in its order
approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
and
the Ohio Companies. The Appellees’ Merit Briefs were filed on August 24, 2006
and the Appellants’ Reply Briefs were filed on September 21, 2006. The OCC
filed an amicus brief on August 4, 2006, which the Ohio Companies moved to
strike as improperly filed. The Supreme Court denied the Ohio Companies’ motion
on October 18, 2006.
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 recovered from January 1 through June 30,
2006 were approximately $61 million. That amount included the recovery of a
portion of the 2005 deferred MISO expenses as described below. On April 27,
2006, the Ohio Companies filed the annual update rider to determine revenues
($139 million) from July 2006 through June 2007. The filed rider went into
effect on July 1, 2006.
The second application sought authority to defer costs associated with
transmission and ancillary service related costs incurred during the period
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. On
January 20,
2006, the OCC sought rehearing of the PUCO’s 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. 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
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 were heard on May 10, 2006. The Ohio Companies are
awaiting a final ruling from the Ohio Supreme Court, which is expected before
the end of 2006.
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 and the companies filed initial
testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this
proceeding with the April 10, 2006 comprehensive rate filing proceeding
discussed below. Met-Ed and Penelec are unable to predict the outcome of
this
matter.
In an October 16, 2003 order, the PPUC approved June 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 were held on June 8, 2006. On July 19, 2006, the
Commonwealth Court issued its decision affirming the PPUC’s prior orders.
Although the decision denied the appeal of Met-Ed and Penelec, they had
previously accounted for the treatment of costs required by the PPUC’s October
2003 orders.
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 an agent for Met-Ed or Penelec in procuring the
services under 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. On September 26, 2006, Met-Ed and
Penelec successfully conducted a competitive RFP for 33% of their PLR obligation
for which Committed Resources have not been obtained for the period
December 1, 2006 through December 31, 2008.
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, further reduce,
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 CBP 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 of $37 million annually and an increase in distribution
rates for Penelec of $20 million annually. The PPUC suspended the effective
date (June 10, 2006) of these rate changes for seven months after the
filing as permitted under Pennsylvania law. If the PPUC adopts the overall
positions taken in the intervenors’ testimony as filed, this would have a
material adverse effect on the financial statements of FirstEnergy, Met-Ed
and
Penelec. Hearings were held in late August 2006 and all reply briefs were
filed
by October 6, 2006. The ALJ’s recommended decision is due by November 8,
2006 and the PPUC decision is expected by January 12, 2007.
As of September 30, 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 were
$297 million and $56 million, respectively. Penelec's $56 million
is subject to the pending resolution of taxable income issues associated
with
NUG trust fund proceeds. The PPUC recently conducted a review and audit of
a
modification to the NUG purchased power stranded cost accounting methodology
for
Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring
Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded
cost accounting methodology modification had not been implemented. As a result
of the PPUC’s Order, Met-Ed recognized a pre-tax charge of approximately $10.3
million in the third quarter of 2006, representing incremental costs deferred
under the revised methodology in 2005. Met-Ed and Penelec continue to believe
that the stranded cost accounting methodology modification is appropriate
and
filed a petition with the PPUC pursuant to its Order for authorization to
reflect the stranded cost accounting methodology modification effective January
1, 1999.
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 all intervened in the case. 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 above. On May 4, 2006, the PPUC
approved the modified request. Accordingly, Met-Ed and Penelec have deferred
approximately $90 million and $21 million, respectively, representing
transmission costs that were incurred from January 1, 2006 through
September 30, 2006. On June 5, 2006, the OCA filed before the
Commonwealth Court a petition for review of the PPUC’s approval of the deferral.
On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the
OCA’s appeal. The ratemaking treatment of the deferrals will be determined in
the comprehensive rate filing proceeding discussed further above.
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 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 before the PPUC 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. On April 20, 2006, the PPUC approved the
Recommended Decision with additional modifications to use an RFP process
with
two separate solicitations. An initial solicitation was held for Penn in
May
2006 with all tranches fully subscribed, which was approved by the PPUC on
June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
Penn. The tranches for the Residential Group and Small Commercial Group were
fully subscribed. However, supply was not acquired for two tranches for the
Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
for
the second bid. A contingency solicitation was held on August 15, 2006 for
the two remaining Large Commercial Group tranches. The PPUC rejected the
bids
from the contingency solicitation and directed Penn’s independent auction
manager to offer the two unfilled Large Commercial tranches to the companies
which had won tranches in the prior solicitations. This resulted in the
acquisition of a supplier for the two remaining tranches, which were filed
and
accepted by the PPUC in a secretarial letter that was entered on
September 22, 2006. On August 24, 2006, Penn made a compliance filing.
OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
exceptions on September 5, 2006. On September 21, 2006, Penn submitted
a revised compliance filing to the PPUC for the Residential Group and Small
Commercial Group as a result of an agreement between Penn, OCA and OSBA.
The PPUC
approved
proposed rates for the large commercial and industrial customers at the PPUC
Public meeting on October 19, 2006, and found that the results of the
competitive solicitation process were consistent with prevailing market
prices.
On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
April 28, 2006 and May 4, 2006, which together decided the issues
associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
impose a geographic limitation on the sources of alternative energy credits.
On
June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
ruling on the method by which alternative energy credits may be acquired
and
traded. Penn is unable to predict the outcome of this appeal.
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 September 30, 2006, the
accumulated deferred cost balance totaled approximately $340 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
bonds associated with BGS stranded cost deferrals. On August 10, 2006,
JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued
$182 million of transition bonds with a weighted average interest rate of
5.5%.
On
December 2, 2005, JCP&L filed its 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 23, 2006, JCP&L filed updated data
reflecting actual amounts through December 31, 2005 of $154 million of
costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing
conference was held with the presiding ALJ. On July 18, 2006, JCP&L
filed rebuttal testimony that included a request for an additional
$14 million of costs that had been eliminated from the securitized amount.
Evidentiary hearings were held during September 2006 and the briefing schedule
has been postponed pending settlement discussions.
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 latest quarterly reliability reports were submitted on
September 12, 2006. As of September 30, 2006, there were no
performance penalties issued by the NJBPU.
Reacting 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. On June 21, 2006,
the NJBPU approved the continued use of a descending block auction for the
Fixed
Price Residential Class. JCP&L filed its 2007 BGS company specific addendum
on July 10, 2006. On October 27, 2006, the NJBPU approved the auction
format to procure the 2007 Commercial Industrial Energy Price as well as
the
specific rules for both the Fixed Price and Commercial Industrial Energy
Price
auctions. These rules were essentially unchanged from the prior
auctions.
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 the Ratepayer Advocate’s comments. A schedule for
further NJBPU 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 repeal
of
PUHCA pursuant to 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 on February 7, 2006 and comments were submitted
to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with
an effective date of October 2, 2006. These regulations are not expected
to
materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the
NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing
various issues including access to books and records, ring-fencing, cross
subsidization, corporate governance and related matters. With the approval
of
the NJBPU Staff, the affected utilities jointly submitted an alternative
proposal on June 1, 2006. Comments on the alternative proposal were submitted
on
June 15, 2006.
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. JCP&L filed a request with the IRS for a ruling on the issue. JCP&L
was advised by the IRS on April 10, 2006 that the ruling was tentatively
adverse. On April 28, 2006, the NJBPU directed JCP&L to withdraw its
request for a private letter ruling on this issue, which had been previously
filed with the IRS as ordered by the NJBPU. On May 11, 2006, after a JCP&L
Motion for Reconsideration was denied by the NJBPU, JCP&L filed to withdraw
the request for a private letter ruling. On July 19, 2006, the IRS acknowledged
that the JCP&L ruling request was withdrawn.
FERC
MATTERS
On November 1, 2004, ATSI filed with the FERC a request to defer approximately
$54 million of costs to be incurred from 2004 through 2007 in connection
with
ATSI’s 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 $34
million has been deferred as of September 30, 2006). On March 28, 2006, ATSI
and
MISO filed with the 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 was
June
1, 2006. Various parties filed comments responsive to the March 28, 2006
submission. The FERC conditionally approved the filing on May 22, 2006, subject
to a compliance filing that ATSI made on June 13, 2006. A request for rehearing
of the FERC’s May 22, 2006 Order was filed by a party, which ATSI answered. On
July 14, 2006, the FERC accepted ATSI’s June 13, 2006 compliance filing.
The estimated annual revenues to ATSI from the VMEP cost recovery is $12
million
for each of the five years beginning June 1, 2006. On October 25,
2006, the FERC denied the request for rehearing.
On
January 24, 2006,
ATSI and MISO filed a request with the FERC 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 RTOR.
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,
the FERC approved the revenue credit correction without suspension, effective
April 1, 2006. One party sought rehearing of the FERC's order. The request
for
rehearing of this order was denied on June 27, 2006. The FERC accepted MISO’s
and ATSI’s revised tariff sheets for filing on June 7, 2006. The estimated
annual revenue impact of the correction mechanism is approximately $40 million
effective on June 1, 2006.
On
November 18,
2004, the FERC issued an order eliminating the RTOR for transmission service
between the MISO and PJM regions. The FERC also ordered the MISO, PJM and
the
transmission owners within MISO and PJM to submit compliance filings containing
a SECA mechanism 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 was held in May 2006. Initial briefs were submitted
on
June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding
Judge
issued an Initial Decision on August 10, 2006, rejecting the compliance filings
made by the RTOs and transmission owners, ruling on various issues and directing
new compliance filings. This decision is subject to review and approval by
the
FERC. Briefs addressing the Initial Decision were filed on September 11,
2006
and October 20, 2006. A final order could be issued by the FERC by the end
of
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 refund 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. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
the cost of all PJM transmission facilities should be recovered through a
postage stamp rate. The
ALJ recommended
an April 1, 2006 effective date for this change in rate design. If the FERC
accepts this recommendation, the transmission rate applicable to many load
zones
in PJM would increase. FirstEnergy believes that significant additional
transmission revenues would have to be recovered from the JCP&L, Met-Ed and
Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
on August 14, 2006 and September 5, 2006. The case will be reviewed by the
FERC with a decision anticipated in the fourth quarter of 2006.
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 CBP 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.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio CBP, 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. Under the procedural
schedule approved in this case, FES expected an initial decision to be issued
in
late January 2007. However, on July 14, 2006, the Chief Judge granted the
joint
motion of FES and the Trial Staff to appoint a settlement judge in this
proceeding and the procedural schedule was suspended pending settlement
discussions among the parties. A settlement conference was held on September
5,
2006. FES and the Ohio Companies, Penn, and the PUCO, along
with other
parties, reached an agreement to settle the case. The settlement was filed
with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. Initial comments to the settlement are due
by
November 6, 2006.
The
terms of the
settlement provide for modification of both the Ohio and Penn power supply
agreements with FES. Under the Ohio power supply agreement, separate rates
are
established for the Ohio Companies’ PLR requirements, special retail contracts
requirements, wholesale contract requirements, and interruptible buy-through
retail load requirements. For their PLR and special retail contract
requirements, the Ohio Companies will pay FES no more than the lower of
(i) the
sum of the retail generation charge, the rate stabilization charge, the
fuel
recovery mechanism charge, and FES’ actual incremental fuel costs for such
sales; or (ii) the wholesale price cap. Different wholesale price caps
are
imposed for PLR sales, special retail contracts, and wholesale contracts.
The
wholesale price for interruptible buy-through retail load requirements
is
limited to the actual spot price of power obtained by FES to provide this
power.
The Ohio Companies have recognized the estimated additional amount payable
to
FES for power supplied during the nine months ended September 30, 2006.
The
wholesale rate charged by FES under the Penn power supply agreement will
be no
greater than the generation component of charges for retail PLR load in
Pennsylvania. The FERC is expected to act on this case by the end of the
fourth
quarter of 2006.
As
a result of
Penn’s PLR competitive solicitation process approved by the PPUC, FES was
selected as the winning bidder for a number of the tranches for individual
customer classes. The balance of the tranches will be supplied by unaffiliated
power suppliers. On October 2, 2006, FES filed an application with FERC under
Section 205 of the Federal Power Act for authorization to make these affiliate
sales to Penn. Interventions or protests were due on this filing on October
23,
2006. Penn was the only party to file an intervention in this proceeding.
The FERC
is expected
to act on this filing on or before December 1, 2006.
On
October 19, 2006,
the FERC issued two final rules in connection with the Public Utility Holding
Company Act of 2005 (PUHCA 2005). The final rules impose certain accounting,
reporting and record-retention requirements for applicable holding companies
and
service companies, which includes FirstEnergy and certain of its
subsidiaries.
12.
- NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In
September 2006, the SEC issued SAB 108, which provides interpretive guidance
on
how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments
will
need to be reconsidered using both the rollover and iron curtain methods.
This
guidance will be effective for FirstEnergy in the fourth quarter of 2006.
FE
does
not expect this Statement to have a material impact on its financial
statements.
EITF
06-5 -
“Accounting for Purchases of Life Insurance-Determining the Amount That Could
Be
Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting
for
Purchases of Life Insurance”
In September 2006, the EITF reached a consensus on Issue 06-5 concluding
that a
policyholder should consider any additional amounts included in the contractual
terms of the policy in determining the amount that could be realized under
the
insurance contract. Contractual limitations should be considered when
determining the realizable amounts. Amounts that are recoverable by the
policyholder at the discretion of the insurance company should be excluded
from
the amount that could be realized. Recoverable amounts in periods beyond
one
year from the surrender of the policy should be discounted in accordance
with
APB Opinion No. 21, “Interest on Receivables and Payables.” Consensus was
also reached that a policyholder should determine the amount that could be
realized under the insurance contract assuming the surrender of an
individual-life by individual-life policy (or certificate by certificate
in a
group policy). Any amount that would ultimately be realized by the policyholder
upon the assumed surrender of the final policy (or final certificate) should
be
included in the amount that could be realized under the insurance contract.
The
EITF also concluded that a policyholder should not discount the cash surrender
value component of the amount that could be realized when contractual
restrictions on the ability to surrender a policy exist. However, if the
contractual limitations prescribe that the cash surrender value component
of the
amount that could be realized is a fixed amount, then the amount that could
be
realized should be discounted in accordance with APB Opinion No. 21. This
Issue is effective for fiscal years beginning after December 15, 2006.
FirstEnergy does not expect this EITF to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157, that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such
as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
FirstEnergy is currently evaluating the impact of this Statement on its
financial statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit
plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized
as a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or
losses,
prior service costs or credits, and transition asset or obligation. Upon
the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for FirstEnergy as of December 31, 2006. Based upon
the December 31, 2005 measurement date, the estimated balance sheet impacts
of adopting this Statement are a reduction in total assets of $0.4 billion,
an increase in liabilities of $0.6 billion and a decrease in equity of
$1 billion, before
recognition
of any related regulatory assets that may be appropriate under the
circumstances.
FSP
FIN 46(R)-6
- “Determining the Variability to Be Considered in Applying FASB interpretation
No. 46(R)”
In
April 2006, the
FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
determine the variability to be considered in applying FASB interpretation
No.
46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter
of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
determined to be the VIE’s primary beneficiary. The variability that is
considered in applying interpretation 46(R) affects the determination of
(a)
whether the entity is a VIE; (b) which interests are variable interests in
the
entity; and (c) which party, if any, is the primary beneficiary of the VIE.
This
FSP states that the variability to be considered shall be based on an analysis
of the design of the entity, involving two steps:
Step
1:
|
Analyze
the
nature of the risks in the entity
|
Step
2:
|
Determine
the
purpose(s) for which the entity was created and determine the variability
the entity is designed to create and pass along to its interest
holders.
|
After
determining
the variability to consider, the reporting enterprise can determine which
interests are designed to absorb that variability. The guidance in this FSP
is
applied prospectively to all entities (including newly created entities)
with
which that enterprise first becomes involved and to all entities previously
required to be analyzed under interpretation 46(R) when a reconsideration
event
has occurred after July 1, 2006. FirstEnergy does not expect this Statement
to have a material impact on its financial statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine
if it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. FirstEnergy
is
currently evaluating the impact of this Statement.
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 September 30, 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 the electric power
needs
of FirstEnergy’s end-use customers through retail and wholesale arrangements,
including regulated retail sales to meet all or a portion of the PLR
requirements of FirstEnergy's Ohio and Pennsylvania companies and competitive
retail sales to customers primarily in Ohio, Pennsylvania, Maryland and
Michigan. This business segment owns and operates FirstEnergy's generating
facilities and purchases electricity 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 revised 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 the revised 2005 segment reporting
primarily includes the transfer 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 rates used in the two reportable segments’ results for 2005
and 2006 have been changed to 40% from the 41% previously reported in their
2005
segment results. The net amounts of the changes in the 2005 reportable segments'
income taxes reclassifications have been correspondingly offset in the 2005
"Reconciling Adjustments." FSG is being disclosed as a reportable 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)
|
|
September
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,290
|
|
$
|
2,066
|
|
$
|
47
|
|
$
|
14
|
|
$
|
(16
|
)
|
$
|
3,401
|
|
Internal
revenues
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
revenues
|
|
|
1,290
|
|
|
2,066
|
|
|
47
|
|
|
14
|
|
|
(16
|
)
|
|
3,401
|
|
Depreciation
and amortization
|
|
|
280
|
|
|
(44
|
)
|
|
-
|
|
|
1
|
|
|
6
|
|
|
243
|
|
Investment
Income
|
|
|
67
|
|
|
19
|
|
|
-
|
|
|
-
|
|
|
(40
|
)
|
|
46
|
|
Net
interest
charges
|
|
|
102
|
|
|
56
|
|
|
-
|
|
|
1
|
|
|
21
|
|
|
180
|
|
Income
taxes
|
|
|
200
|
|
|
119
|
|
|
-
|
|
|
(15
|
)
|
|
(32
|
)
|
|
272
|
|
Income
before
discontinued operations
|
|
|
297
|
|
|
180
|
|
|
1
|
|
|
27
|
|
|
(51
|
)
|
|
454
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
income
|
|
|
297
|
|
|
180
|
|
|
1
|
|
|
27
|
|
|
(51
|
)
|
|
454
|
|
Total
assets
|
|
|
24,181
|
|
|
6,822
|
|
|
30
|
|
|
290
|
|
|
839
|
|
|
32,162
|
|
Total
goodwill
|
|
|
5,911
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,935
|
|
Property
additions
|
|
|
123
|
|
|
126
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,481
|
|
$
|
1,824
|
|
$
|
59
|
|
$
|
138
|
|
$
|
2
|
|
$
|
3,504
|
|
Internal
revenues
|
|
|
79
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(79
|
)
|
|
-
|
|
Total
revenues
|
|
|
1,560
|
|
|
1,824
|
|
|
59
|
|
|
138
|
|
|
(77
|
)
|
|
3,504
|
|
Depreciation
and amortization
|
|
|
409
|
|
|
(22
|
)
|
|
-
|
|
|
1
|
|
|
5
|
|
|
393
|
|
Investment
income
|
|
|
83
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
83
|
|
Net
interest
charges
|
|
|
88
|
|
|
11
|
|
|
-
|
|
|
1
|
|
|
57
|
|
|
157
|
|
Income
taxes
|
|
|
264
|
|
|
(9
|
)
|
|
-
|
|
|
3
|
|
|
(21
|
)
|
|
237
|
|
Income
before
discontinued operations
|
|
|
395
|
|
|
(13
|
)
|
|
-
|
|
|
6
|
|
|
(56
|
)
|
|
332
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
income
|
|
|
395
|
|
|
(13
|
)
|
|
-
|
|
|
6
|
|
|
(56
|
)
|
|
332
|
|
Total
assets
|
|
|
28,385
|
|
|
1,741
|
|
|
82
|
|
|
522
|
|
|
644
|
|
|
31,374
|
|
Total
goodwill
|
|
|
5,938
|
|
|
24
|
|
|
-
|
|
|
62
|
|
|
-
|
|
|
6,024
|
|
Property
additions
|
|
|
207
|
|
|
79
|
|
|
-
|
|
|
1
|
|
|
7
|
|
|
294
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
3,417
|
|
$
|
5,364
|
|
$
|
150
|
|
$
|
149
|
|
$
|
(49
|
)
|
$
|
9,031
|
|
Internal
revenues
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
revenues
|
|
|
3,417
|
|
|
5,364
|
|
|
150
|
|
|
149
|
|
|
(49
|
)
|
|
9,031
|
|
Depreciation
and amortization
|
|
|
765
|
|
|
(54
|
)
|
|
-
|
|
|
3
|
|
|
17
|
|
|
731
|
|
Investment
Income
|
|
|
204
|
|
|
36
|
|
|
-
|
|
|
1
|
|
|
(121
|
)
|
|
120
|
|
Net
interest
charges
|
|
|
291
|
|
|
160
|
|
|
-
|
|
|
5
|
|
|
57
|
|
|
513
|
|
Income
taxes
|
|
|
499
|
|
|
236
|
|
|
2
|
|
|
(21
|
)
|
|
(93
|
)
|
|
623
|
|
Income
before
discontinued operations
|
|
|
736
|
|
|
355
|
|
|
(11
|
)
|
|
37
|
|
|
(138
|
)
|
|
979
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
income
|
|
|
736
|
|
|
355
|
|
|
(11
|
)
|
|
37
|
|
|
(138
|
)
|
|
979
|
|
Total
assets
|
|
|
24,181
|
|
|
6,822
|
|
|
30
|
|
|
290
|
|
|
839
|
|
|
32,162
|
|
Total
goodwill
|
|
|
5,911
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,935
|
|
Property
additions
|
|
|
492
|
|
|
473
|
|
|
-
|
|
|
2
|
|
|
23
|
|
|
990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
3,923
|
|
$
|
4,617
|
|
$
|
162
|
|
$
|
385
|
|
$
|
10
|
|
$
|
9,097
|
|
Internal
revenues
|
|
|
238
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(238
|
)
|
|
-
|
|
Total
revenues
|
|
|
4,161
|
|
|
4,617
|
|
|
162
|
|
|
385
|
|
|
(228
|
)
|
|
9,097
|
|
Depreciation
and amortization
|
|
|
1,128
|
|
|
(26
|
)
|
|
-
|
|
|
2
|
|
|
18
|
|
|
1,122
|
|
Investment
income
|
|
|
171
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
171
|
|
Net
interest
charges
|
|
|
285
|
|
|
29
|
|
|
1
|
|
|
4
|
|
|
170
|
|
|
489
|
|
Income
taxes
|
|
|
613
|
|
|
(43
|
)
|
|
4
|
|
|
13
|
|
|
12
|
|
|
599
|
|
Income
before
discontinued operations
|
|
|
920
|
|
|
(64
|
)
|
|
(6
|
)
|
|
18
|
|
|
(216
|
)
|
|
652
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
13
|
|
|
5
|
|
|
-
|
|
|
18
|
|
Net
income
|
|
|
920
|
|
|
(64
|
)
|
|
7
|
|
|
23
|
|
|
(216
|
)
|
|
670
|
|
Total
assets
|
|
|
28,385
|
|
|
1,741
|
|
|
82
|
|
|
522
|
|
|
644
|
|
|
31,374
|
|
Total
goodwill
|
|
|
5,938
|
|
|
24
|
|
|
-
|
|
|
62
|
|
|
-
|
|
|
6,024
|
|
Property
additions
|
|
|
506
|
|
|
226
|
|
|
1
|
|
|
5
|
|
|
18
|
|
|
756
|
|
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.
15.
-
JCP&L RESTATEMENT
JCP&L's
earnings
for the three months and nine months ended September 30, 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
$0.7 million and $0.6 million, respectively, in the third quarter of
2005 and understated by $1.6 million and $1.8 million, respectively,
in the nine months ended September 30, 2005. The effects of these
adjustments on JCP&L's Consolidated Statements of Income for the three
months and nine months ended September 30, 2005 are as
follows:
|
|
Three
Months
|
|
Nine
Months
|
|
|
As
Previously
|
|
|
As
|
|
As
Previously
|
|
As
|
|
|
Reported
|
|
|
Restated
|
|
Reported
|
|
Restated
|
|
|
(In
millions)
|
Operating
Revenues
|
$
|
900.3
|
|
$
|
900.3
|
|
$
|
2,024.7
|
|
$
|
2,024.7
|
Operating
Expenses and
|
|
|
|
|
|
|
|
|
|
|
|
Taxes
|
|
809.2
|
|
|
809.9
|
|
|
1,825.1
|
|
|
1,826.7
|
Operating
Income
|
|
91.1
|
|
|
90.4
|
|
|
199.6
|
|
|
198.0
|
Other
Income
|
|
3.0
|
|
|
3.0
|
|
|
3.3
|
|
|
3.3
|
Net
Interest
Charges
|
|
18.9
|
|
|
19.5
|
|
|
57.9
|
|
|
59.7
|
Net
Income
|
$
|
75.2
|
|
$
|
73.9
|
|
$
|
145.0
|
|
$
|
141.6
|
Earnings
Applicable
|
|
|
|
|
|
|
|
|
|
|
|
to
Common
Stock
|
$
|
75.0
|
|
$
|
73.8
|
|
$
|
144.6
|
|
$
|
141.3
|
These
adjustments
were not material to FirstEnergy's consolidated financial statements, nor
JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash
Flows.
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Electric
utilities
|
|
$
|
2,996
|
|
$
|
2,853
|
|
$
|
7,677
|
|
$
|
7,403
|
|
Unregulated
businesses
|
|
|
405
|
|
|
651
|
|
|
1,354
|
|
|
1,694
|
|
Total
revenues
|
|
|
3,401
|
|
|
3,504
|
|
|
9,031
|
|
|
9,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
1,317
|
|
|
1,287
|
|
|
3,306
|
|
|
3,115
|
|
Other
operating expenses
|
|
|
794
|
|
|
993
|
|
|
2,446
|
|
|
2,750
|
|
Provision
for
depreciation
|
|
|
153
|
|
|
152
|
|
|
445
|
|
|
444
|
|
Amortization
of regulatory assets
|
|
|
243
|
|
|
366
|
|
|
665
|
|
|
983
|
|
Deferral
of
new regulatory assets
|
|
|
(153
|
)
|
|
(125
|
)
|
|
(379
|
)
|
|
(305
|
)
|
General
taxes
|
|
|
187
|
|
|
188
|
|
|
553
|
|
|
541
|
|
Total
expenses
|
|
|
2,541
|
|
|
2,861
|
|
|
7,036
|
|
|
7,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
860
|
|
|
643
|
|
|
1,995
|
|
|
1,569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
46
|
|
|
83
|
|
|
120
|
|
|
171
|
|
Interest
expense
|
|
|
(185
|
)
|
|
(162
|
)
|
|
(528
|
)
|
|
(488
|
)
|
Capitalized
interest
|
|
|
7
|
|
|
8
|
|
|
21
|
|
|
12
|
|
Subsidiaries’
preferred stock dividends
|
|
|
(2
|
)
|
|
(3
|
)
|
|
(6
|
)
|
|
(13
|
)
|
Total
other
expense
|
|
|
(134
|
)
|
|
(74
|
)
|
|
(393
|
)
|
|
(318
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS
|
|
|
726
|
|
|
569
|
|
|
1,602
|
|
|
1,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
272
|
|
|
237
|
|
|
623
|
|
|
599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
|
454
|
|
|
332
|
|
|
979
|
|
|
652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
$9 million)
(Note 4)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
454
|
|
$
|
332
|
|
$
|
979
|
|
$
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations (Note 2)
|
|
$
|
1.41
|
|
$
|
1.01
|
|
$
|
2.99
|
|
$
|
1.99
|
|
Discontinued
operations (Note 4)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
Net
earnings
per basic share
|
|
$
|
1.41
|
|
$
|
1.01
|
|
$
|
2.99
|
|
$
|
2.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OUTSTANDING
|
|
|
322
|
|
|
328
|
|
|
326
|
|
|
328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations (Note 2)
|
|
$
|
1.40
|
|
$
|
1.01
|
|
$
|
2.97
|
|
$
|
1.98
|
|
Discontinued
operations (Note 4)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
Net
earnings
per diluted share
|
|
$
|
1.40
|
|
$
|
1.01
|
|
$
|
2.97
|
|
$
|
2.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OUTSTANDING
|
|
|
325
|
|
|
330
|
|
|
329
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$
|
0.45
|
|
$
|
0.43
|
|
$
|
1.35
|
|
$
|
1.255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Corp. are an integral part of these
|
|
statements.
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
454
|
|
$
|
332
|
|
$
|
979
|
|
$
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
(28
|
)
|
|
18
|
|
|
45
|
|
|
19
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
26
|
|
|
(13
|
)
|
|
39
|
|
|
(37
|
)
|
Other
comprehensive income (loss)
|
|
|
(2
|
)
|
|
5
|
|
|
84
|
|
|
(18
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(1
|
)
|
|
(2
|
)
|
|
30
|
|
|
(8
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
(1
|
)
|
|
7
|
|
|
54
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
$
|
453
|
|
$
|
339
|
|
$
|
1,033
|
|
$
|
660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of
|
|
these
statements.
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
$
|
41
|
|
$
|
64
|
|
Receivables
-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $44 million and
|
|
|
|
|
|
|
|
|
$38
million,
respectively, for uncollectible accounts)
|
|
|
|
1,226
|
|
|
1,293
|
|
Other
(less
accumulated provisions of $26 million and
|
|
|
|
|
|
|
|
|
$27
million,
respectively, for uncollectible accounts)
|
|
|
|
194
|
|
|
205
|
|
Materials
and
supplies, at average cost
|
|
|
|
585
|
|
|
518
|
|
Prepayments
and other
|
|
|
|
168
|
|
|
237
|
|
|
|
|
|
2,214
|
|
|
2,317
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
|
23,823
|
|
|
22,893
|
|
Less
-
Accumulated provision for depreciation
|
|
|
|
9,986
|
|
|
9,792
|
|
|
|
|
|
13,837
|
|
|
13,101
|
|
Construction
work in progress
|
|
|
|
673
|
|
|
897
|
|
|
|
|
|
14,510
|
|
|
13,998
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
|
1,874
|
|
|
1,752
|
|
Investments
in
lease obligation bonds
|
|
|
|
830
|
|
|
890
|
|
Other
|
|
|
|
770
|
|
|
709
|
|
|
|
|
|
3,474
|
|
|
3,351
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
5,935
|
|
|
6,010
|
|
Regulatory
assets
|
|
|
|
4,434
|
|
|
4,486
|
|
Prepaid
pension costs
|
|
|
|
1,008
|
|
|
1,023
|
|
Other
|
|
|
|
587
|
|
|
656
|
|
|
|
|
|
11,964
|
|
|
12,175
|
|
|
|
|
$
|
32,162
|
|
$
|
31,841
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
$
|
1,667
|
|
$
|
2,043
|
|
Short-term
borrowings
|
|
|
|
1,213
|
|
|
731
|
|
Accounts
payable
|
|
|
|
611
|
|
|
727
|
|
Accrued
taxes
|
|
|
|
752
|
|
|
800
|
|
Other
|
|
|
|
1,021
|
|
|
1,152
|
|
|
|
|
|
5,264
|
|
|
5,453
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholders’ equity -
|
|
|
|
|
|
|
|
|
Common
stock,
$.10 par value, authorized 375,000,000 shares -
|
|
|
|
|
|
|
|
|
319,205,517
and 329,836,276 shares outstanding, respectively
|
|
|
|
32
|
|
|
33
|
|
Other
paid-in
capital
|
|
|
|
6,460
|
|
|
7,043
|
|
Accumulated
other comprehensive income (loss)
|
|
|
|
34
|
|
|
(20
|
)
|
Retained
earnings
|
|
|
|
2,695
|
|
|
2,159
|
|
Unallocated
employee stock ownership plan common stock -
|
|
|
|
|
|
|
|
|
718,671
and
1,444,796 shares, respectively
|
|
|
|
(13
|
)
|
|
(27
|
)
|
Total
common
stockholders' equity
|
|
|
|
9,208
|
|
|
9,188
|
|
Preferred
stock of consolidated subsidiaries
|
|
|
|
80
|
|
|
184
|
|
Long-term
debt
and other long-term obligations
|
|
|
|
8,760
|
|
|
8,155
|
|
|
|
|
|
18,048
|
|
|
17,527
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
|
2,778
|
|
|
2,726
|
|
Asset
retirement obligations
|
|
|
|
1,179
|
|
|
1,126
|
|
Power
purchase
contract loss liability
|
|
|
|
1,205
|
|
|
1,226
|
|
Retirement
benefits
|
|
|
|
1,372
|
|
|
1,316
|
|
Lease
market
valuation liability
|
|
|
|
788
|
|
|
851
|
|
Other
|
|
|
|
1,528
|
|
|
1,616
|
|
|
|
|
|
8,850
|
|
|
8,861
|
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
32,162
|
|
$
|
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)
|
|
|
|
|
|
|
|
Nine Months
Ended
|
|
|
September 30,
|
|
|
2006
|
|
2005
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
$
|
979
|
|
$
|
670
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
445
|
|
|
444
|
|
Amortization
of regulatory assets
|
|
665
|
|
|
983
|
|
Deferral
of
new regulatory assets
|
|
(379
|
)
|
|
(305
|
)
|
Nuclear
fuel
and lease amortization
|
|
67
|
|
|
63
|
|
Deferred
purchased power and other costs
|
|
(323
|
)
|
|
(258
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
36
|
|
|
24
|
|
Deferred
rents
and lease market valuation liability
|
|
(54
|
)
|
|
(71
|
)
|
Accrued
compensation and retirement benefits
|
|
78
|
|
|
72
|
|
Commodity
derivative transactions, net
|
|
28
|
|
|
(8
|
)
|
Gain
on asset
sales
|
|
(38
|
)
|
|
-
|
|
Income
from
discontinued operations
|
|
- |
|
|
(18 |
) |
Cash
collateral
|
|
(98
|
)
|
|
49
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
Receivables
|
|
(7
|
) |
|
(226
|
)
|
Materials
and
supplies
|
|
(30
|
)
|
|
(40
|
)
|
Prepayments
and other current assets
|
|
(49
|
)
|
|
(57
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
Accounts
payable
|
|
(93
|
)
|
|
60
|
|
Accrued
taxes
|
|
(35
|
)
|
|
207
|
|
Accrued
interest
|
|
104
|
|
|
92
|
|
Electric
service prepayment programs
|
|
(45
|
)
|
|
218
|
|
Other
|
|
(8
|
) |
|
17
|
|
Net
cash
provided from operating activities
|
|
1,243
|
|
|
1,916
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
Long-term
debt
|
|
1,235
|
|
|
334
|
|
Short-term
borrowings, net
|
|
482
|
|
|
77
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
Common
stock
|
|
(600 |
) |
|
- |
|
Preferred
stock
|
|
(107
|
)
|
|
(170
|
)
|
Long-term
debt
|
|
(993
|
)
|
|
(852
|
)
|
Net
controlled
disbursement activity
|
|
(22
|
) |
|
(27
|
) |
Common
stock
dividend payments
|
|
(439
|
)
|
|
(411
|
)
|
Net
cash used for financing activities
|
|
(444
|
) |
|
(1,049
|
)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
Property
additions
|
|
(990
|
)
|
|
(756
|
)
|
Proceeds
from
asset sales
|
|
83
|
|
|
61
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
1,325
|
|
|
1,140
|
|
Investments in
nuclear decommissioning trust funds
|
|
(1,336
|
)
|
|
(1,216
|
)
|
Cash
investments
|
|
109
|
|
|
21
|
|
Other
|
|
(13
|
)
|
|
(30
|
)
|
Net
cash used
for investing activities
|
|
(822
|
)
|
|
(780
|
)
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
(23
|
) |
|
87
|
|
Cash
and cash
equivalents at beginning of period
|
|
64
|
|
|
53
|
|
Cash
and cash
equivalents at end of period
|
$
|
41
|
|
$
|
140
|
|
|
|
|
|
|
|
|
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
Stockholders
and
Board of
Directors
of
FirstEnergy Corp.
We
have reviewed the
accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of September 30, 2006, and the related consolidated statements
of income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2006 and 2005 and the consolidated statements of
cash flows for the nine-month periods ended September 30, 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.
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
October
31,
2006
|
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE
SUMMARY
Net income in the third quarter of 2006 was $454 million, or basic earnings
of $1.41 per share of common stock ($1.40 diluted), compared with net income
of
$332 million, or basic and diluted earnings of $1.01 per share of common
stock in the third quarter of 2005. Net income in the first nine months of
2006
was $979 million, or basic earnings of $2.99 per share of common stock
($2.97 diluted) compared to $670 million in the first nine months of 2005,
or basic earnings of $2.04 per share of common stock ($2.03 diluted). The
increase in FirstEnergy’s earnings in both periods was driven primarily by
reduced transition cost amortization for the Ohio Companies, cost deferrals
authorized by the PUCO and PPUC, and reduced operating expenses. Earnings in
the
first nine months of 2006 also reflected increased electric sales revenues.
Net
income in the third quarter and first nine months of 2006 included unusual
charges resulting from the PPUC’s NUG costs accounting order for prior year
deferred costs of $10 million (or $6 million after-tax --$.02 per
share) and the impact from the sale and impairment of non-core assets (or
$1 million after-tax--$0.01 per share). Earnings in the first nine months
of 2005 were reduced by $0.22 per share of common stock due to additional income
tax expense of $71 million from the enactment of tax legislation in Ohio.
The following Non-GAAP Reconciliation displays the unusual items resulting
in
the difference between GAAP and Non-GAAP earnings.
Non-GAAP
to GAAP Reconciliation
|
|
2006
|
|
2005
|
|
|
|
After-tax
|
|
Basic
|
|
After-tax
|
|
Basic
|
|
|
|
Amount
|
|
Earnings
|
|
Amount
|
|
Earnings
|
|
Three
Months Ended September 30,
|
|
(Millions)
|
|
Per
Share
|
|
(Millions)
|
|
Per
Share
|
|
Earnings
Before Unusual Items (Non-GAAP)
|
|
$
|
459
|
|
$
|
1.42
|
|
$
|
342
|
|
$
|
1.04
|
|
Unusual
Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PPUC
NUG
adjustment applicable to prior years
|
|
|
(6
|
)
|
|
(0.02
|
)
|
|
-
|
|
|
-
|
|
Non-core
asset
sales/impairments
|
|
|
1
|
|
|
0.01
|
|
|
-
|
|
|
-
|
|
JCP&L
arbitration decision
|
|
|
-
|
|
|
-
|
|
|
(10
|
)
|
|
(0.03
|
)
|
Net
Income
(GAAP)
|
|
$
|
454
|
|
$
|
1.41
|
|
$
|
332
|
|
$
|
1.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Before Unusual Items (Non-GAAP)
|
|
$
|
995
|
|
$
|
3.04
|
|
$
|
730
|
|
$
|
2.22
|
|
Unusual
Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PPUC
NUG
adjustment applicable to prior years
|
|
|
(6
|
)
|
|
(0.02
|
)
|
|
-
|
|
|
-
|
|
Non-core
asset
sales/impairments
|
|
|
(10
|
)
|
|
(0.03
|
)
|
|
22
|
|
|
0.07
|
|
Sammis
plant
New Source Review settlement
|
|
|
-
|
|
|
-
|
|
|
(14
|
)
|
|
(0.04
|
)
|
Davis-Besse
NRC fine
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
|
(0.01
|
)
|
New
regulatory
assets - JCP&L rate settlement
|
|
|
|
|
|
|
|
|
16
|
|
|
0.05
|
|
JCP&L
arbitration decision
|
|
|
-
|
|
|
-
|
|
|
(10
|
)
|
|
(0.03
|
)
|
Ohio
tax
write-off
|
|
|
-
|
|
|
-
|
|
|
(71
|
)
|
|
(0.22
|
)
|
Net
Income
(GAAP)
|
|
$
|
979
|
|
$
|
2.99
|
|
$
|
670
|
|
$
|
2.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Non-GAAP measure
above, earnings before unusual items, is not calculated in accordance with
GAAP
because it excludes the impact of "unusual items." Unusual items reflect the
impact on earnings of events that are not routine or for which FirstEnergy
believes the financial impact will disappear or become immaterial within a
near-term finite period. By removing the earnings effect of such issues that
have been resolved or are expected to be resolved over the near-term, management
and investors can better measure FirstEnergy’s business and earnings potential.
In particular, the non-core asset sales impairments items refer to a finite
set
of energy-related assets that had been previously disclosed as held for sale,
a
substantial portion of which have already been sold. Similarly, the NRC fine
in
2005 and further litigation settlements similar to the New Source Review
settlement in 2005 are not reasonably expected over the near-term. Furthermore,
FirstEnergy believes presenting normalized earnings calculated in this manner
provides useful information to investors in evaluating the ongoing results
of
FirstEnergy’s businesses over the longer term and assists investors in comparing
FirstEnergy’s operating performance to the operating performance of others in
the energy sector. Generally, a Non-GAAP financial measure is a numerical
measure of a company’s historical or future financial performance, financial
position, or cash flows that either excludes or includes amounts, or is subject
to adjustment that has the effect of excluding or including amounts, that are
not normally excluded or included in the most directly comparable measure
calculated and presented in accordance with GAAP. Earnings per share before
unusual items on a Non-GAAP basis (normalized earnings per share) are not
calculated in accordance with GAAP because it excludes the impact of “unusual
items.” Unusual items reflect the impact on earnings of material events that are
not routine, including those that may be related to discontinued businesses
or
the cumulative effect of an accounting change. Management believes presenting
normalized earnings calculated in this manner provides useful information to
investors in evaluating the ongoing results of FirstEnergy’s businesses and
assists investors in comparing FirstEnergy’s operating performance to the
operating performance of other companies in the energy sector. FirstEnergy’s
management frequently references Non-GAAP financial measures in its
decision-making, using them to facilitate historical and ongoing performance
comparisons as well as comparisons to the performance of peer companies.
Non-GAAP measures should be considered in addition to, and not as a substitute
for, their most directly comparable financial measures prepared in accordance
with GAAP.
Total
electric
generation sales were down 1.3% in the third quarter of 2006 compared to last
year's third quarter. The decrease resulted from a 32.9% reduction in wholesale
sales, which more than offset a 7.7% increase in retail sales. For the nine
months ended September 30, 2006, electric generation sales increased 1.4%
over the same period last year. The year-to-date increase was primarily due
to
the return of customers to the Ohio Companies from third-party suppliers that
exited the northern Ohio marketplace. Electric distribution deliveries were
down
2.3% and 2.2% for the quarter and year-to-date periods ending September 30,
2006, compared with the respective periods of 2005, reflecting milder weather
conditions in 2006.
FirstEnergy's
generating fleet produced a record 61.9 billion KWH during the first nine
months of 2006 compared to 59.5 billion KWH in the same period of 2005.
FirstEnergy's non-nuclear fleet produced a record 40.1 billion KWH, while
its nuclear facilities produced 21.8 billion KWH.
Share Repurchase Program - On
August 10,
2006, FirstEnergy repurchased 10.6 million shares, or approximately 3.2%,
of its outstanding common stock through an accelerated share repurchase program
with an affiliate of J.P. Morgan Securities. The initial purchase price was
$600 million, or $56.44 per share. The final purchase price will be
adjusted to reflect the average of the daily volume-weighted prices of the
shares over a period of up to seven months. The share repurchase was initially
funded with short-term debt. The share repurchase was executed under a
June 20, 2006 Board of Directors’ authorization to repurchase up to
12 million shares of common stock.
Renewed and Upsized Credit Facility - On August 24, 2006, FirstEnergy and
certain of its subsidiaries, including all of its operating utility
subsidiaries, entered into a new five-year syndicated credit facility totaling
$2.75 billion. The new facility replaces FirstEnergy’s previous
$2 billion credit facility and provides an average annual savings of 10
basis points on facility-related borrowing costs. Borrowings under the new
credit facility were used to pay off the outstanding borrowings under the
previous facility. FirstEnergy can request an increase in the total commitments
available under the new facility up to a maximum of $3.25 billion.
Commitments under the new facility are available until August 24, 2011,
unless the lenders agree, at the request of the Borrowers, to two additional
one-year extensions. Generally, borrowings under the facility must be repaid
within 364 days. Available amounts for each Borrower are subject to a specified
sub-limit, as well as applicable regulatory and other limitations.
Pennsylvania Rate Matters - Evidentiary hearings in the Met-Ed and Penelec
rate
transition plan filings were held from August 24 through August 30,
2006. Parties to the proceedings filed their Main Briefs on September 22,
2006 and Reply Briefs on October 6, 2006. Met-Ed and Penelec anticipate an
ALJ recommended decision in these proceedings by November 8, 2006 and a
PPUC decision by January 12, 2007. As part of the transition of customers’
generation service toward market-based supply, Met-Ed and Penelec secured
approximately 950 MW of their PLR supply under a competitive RFP for the period
December 1, 2006 through December 31, 2008. Recovery of the
incremental costs under the RFP is one component of the transition plan
cases.
Met-Ed and Penelec NUG Accounting Methodology - On August 18, 2006,
following a review and audit of FirstEnergy’s modification to its NUG purchased
power stranded cost accounting methodology, the PPUC issued an order requiring
Met-Ed and Penelec to revert to the original accounting methodology under which
NUG regulatory asset balances are reduced when market prices exceed NUG costs
during the month. As a result of the order, FirstEnergy and Met-Ed recognized
a
pre-tax charge of $10 million in the third quarter of 2006, relating to
incremental NUG costs deferred in 2005 under the revised
methodology.
Penn RFP - On October 19, 2006, the PPUC certified the RFP results for all
customer classes reflecting the successful completion of the RFP bidding
process. The RFP was conducted to secure Penn’s PLR supply for the period
January 1, 2007 through May 31, 2008 for those customers that do not
choose alternative suppliers.
JCP&L NUG Proceeding - An evidentiary hearing was held on September 20,
2006 and settlement conferences were held in October 2006 in the proceeding
involving JCP&L’s request to recover $165 million of actual
above-market NUG costs incurred from August 1, 2003 through
December 31, 2005. If approved, this request would increase cash flow, but
would have no impact on earnings. Main briefs were filed October 30, 2006
and reply briefs are due by November 20, 2006. An order by the NJBPU is
expected in 2007.
Beaver Valley Power Station Uprates - In August 2006, Beaver Valley Unit 1
increased its net output capability from 821 MW to 846 MW. This three-percent
increase in capability is the first phase of its overall eight-percent power
uprate recently approved by the NRC. The uprate was made possible by
improvements to plant equipment and systems completed during the Unit’s spring
refueling outage. The remainder of the eight-percent power uprate is expected
to
be implemented by early 2007. Similar work is planned for Beaver Valley Unit
2.
During the Unit’s current refueling outage, which began October 2, 2006,
several modifications will be completed to prepare Beaver Valley Unit 2 for
its
eight-percent increase in generating capacity. After Beaver Valley Unit 2
returns to service, three percent of the uprate is expected to take effect.
The
balance of the eight-percent power output increase is anticipated to be
implemented during the next refueling outage in 2008. Beaver Valley Unit 2
is
expected to return to service from its current refueling outage in early to
mid-November 2006.
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 or,
in some cases, purchased from independent suppliers in the states
where
the utility subsidiaries operate.
|
|
|
·
|
Power
Supply Management Services
supplies the
electric power needs of end-use customers through retail and wholesale
arrangements, including regulated retail sales to meet all or a
portion of
the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility
subsidiaries and competitive retail sales to customers primarily
in Ohio,
Pennsylvania, Maryland and Michigan. This business segment owns
and
operates FirstEnergy's generating facilities and purchases electricity
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 related 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
In 2005, the Ohio Companies and Penn 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 FirstEnergy’s consolidated
results.
RESULTS
OF
OPERATIONS
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 September 30,
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
|
|
Increase
|
|
|
|
Increase
|
|
|
|
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
|
|
(In
millions, except per share amounts)
|
|
Net
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By
Business Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Services
|
|
|
|
|
$
|
297
|
|
$
|
395
|
|
$
|
(98
|
)
|
$
|
736
|
|
$
|
920
|
|
$
|
(184
|
)
|
Power
supply
management services
|
|
|
|
|
|
180
|
|
|
(13
|
)
|
|
193
|
|
|
355
|
|
|
(64
|
)
|
|
419
|
|
Other
and
reconciling adjustments*
|
|
|
|
|
|
(23
|
)
|
|
(50
|
)
|
|
27
|
|
|
(112
|
)
|
|
(186
|
)
|
|
74
|
|
Total
|
|
|
|
|
$
|
454
|
|
$
|
332
|
|
$
|
122
|
|
$
|
979
|
|
$
|
670
|
|
$
|
309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
|
|
|
$
|
1.41
|
|
$
|
1.01
|
|
$
|
0.40
|
|
$
|
2.99
|
|
$
|
1.99
|
|
$
|
1.00
|
|
Discontinued
operations
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
|
(0.05
|
)
|
Net
earnings
per basic share
|
|
|
|
|
$
|
1.41
|
|
$
|
1.01
|
|
$
|
0.40
|
|
$
|
2.99
|
|
$
|
2.04
|
|
$
|
0.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
|
|
|
$
|
1.40
|
|
$
|
1.01
|
|
$
|
0.39
|
|
$
|
2.97
|
|
$
|
1.98
|
|
$
|
0.99
|
|
Discontinued
operations
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
|
(0.05
|
)
|
Net
earnings
per diluted share
|
|
|
|
|
$
|
1.40
|
|
$
|
1.01
|
|
$
|
0.39
|
|
$
|
2.97
|
|
$
|
2.03
|
|
$
|
0.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
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
third quarter and the first nine months of 2006 included a $10 million
($6 million after-tax) charge (or $0.02 per share) applicable to prior year
NUG costs resulting from an August 2006 PPUC accounting order. Net income in
the
first nine months of 2006 was also reduced by the net charges associated with
the sale and impairment of non-core assets of $10 million (or $0.03 per
share).
Net income in the third quarter of 2005 included a $16 million
($10 million after-tax) charge (or $0.03 per share) resulting from a
JCP&L arbitration decision. In the first nine months of 2005, net income was
further reduced by additional income tax expense of $71 million (or $0.22
per share) from the enactment of tax legislation in Ohio, $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 NRC regarding the
Davis-Besse Nuclear Power Station. These reductions were partially offset by
the
combined impact of $0.07 per share of gains from the sale of non-core assets
and
a net benefit resulting from the JCP&L rate settlement of $16 million
(or $0.05 per share).
Summary
of Results of
Operations - Third Quarter of 2006 Compared with the Third Quarter of
2005
Financial
results
for FirstEnergy's major business segments in the third quarter of 2006 and
2005
were as follows:
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
3rd
Quarter 2006 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,124
|
|
$
|
1,991
|
|
$
|
-
|
|
$
|
3,115
|
|
Other
|
|
|
166
|
|
|
75
|
|
|
45
|
|
|
286
|
|
Internal
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
Revenues
|
|
|
1,290
|
|
|
2,066
|
|
|
45
|
|
|
3,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
1,317
|
|
|
-
|
|
|
1,317
|
|
Other
operating expenses
|
|
|
338
|
|
|
414
|
|
|
42
|
|
|
794
|
|
Provision
for
depreciation
|
|
|
96
|
|
|
50
|
|
|
7
|
|
|
153
|
|
Amortization
of regulatory assets
|
|
|
238
|
|
|
5
|
|
|
-
|
|
|
243
|
|
Deferral
of
new regulatory assets
|
|
|
(54
|
)
|
|
(99
|
)
|
|
-
|
|
|
(153
|
)
|
General
taxes
|
|
|
140
|
|
|
43
|
|
|
4
|
|
|
187
|
|
Total
Expenses
|
|
|
758
|
|
|
1,730
|
|
|
53
|
|
|
2,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
532
|
|
|
336
|
|
|
(8
|
)
|
|
860
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
67
|
|
|
19
|
|
|
(40
|
)
|
|
46
|
|
Interest
expense
|
|
|
(104
|
)
|
|
(58
|
)
|
|
(23
|
)
|
|
(185
|
)
|
Capitalized
interest
|
|
|
4
|
|
|
2
|
|
|
1
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(2
|
)
|
|
-
|
|
|
-
|
|
|
(2
|
)
|
Total
Other
Income (Expense)
|
|
|
(35
|
)
|
|
(37
|
)
|
|
(62
|
)
|
|
(134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
income taxes
|
|
|
497
|
|
|
299
|
|
|
(70
|
)
|
|
726
|
|
Income
tax
expense (benefit)
|
|
|
200
|
|
|
119
|
|
|
(47
|
)
|
|
272
|
|
Net
Income
(Loss)
|
|
$
|
297
|
|
$
|
180
|
|
$
|
(23
|
)
|
$
|
454
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
3rd
Quarter 2005 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,340
|
|
$
|
1,777
|
|
$
|
-
|
|
$
|
3,117
|
|
Other
|
|
|
141
|
|
|
47
|
|
|
199
|
|
|
387
|
|
Internal
|
|
|
79
|
|
|
-
|
|
|
(79
|
)
|
|
-
|
|
Total
Revenues
|
|
|
1,560
|
|
|
1,824
|
|
|
120
|
|
|
3,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
1,287
|
|
|
-
|
|
|
1,287
|
|
Other
operating expenses
|
|
|
337
|
|
|
537
|
|
|
119
|
|
|
993
|
|
Provision
for
depreciation
|
|
|
137
|
|
|
9
|
|
|
6
|
|
|
152
|
|
Amortization
of regulatory assets
|
|
|
366
|
|
|
-
|
|
|
-
|
|
|
366
|
|
Deferral
of
new regulatory assets
|
|
|
(94
|
)
|
|
(31
|
)
|
|
-
|
|
|
(125
|
)
|
General
taxes
|
|
|
150
|
|
|
33
|
|
|
5
|
|
|
188
|
|
Total
Expenses
|
|
|
896
|
|
|
1,835
|
|
|
130
|
|
|
2,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
664
|
|
|
(11
|
)
|
|
(10
|
)
|
|
643
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
83
|
|
|
-
|
|
|
-
|
|
|
83
|
|
Interest
expense
|
|
|
(91
|
)
|
|
(12
|
)
|
|
(58
|
)
|
|
(161
|
)
|
Capitalized
interest
|
|
|
6
|
|
|
1
|
|
|
-
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(3
|
)
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
Total
Other
Income (Expense)
|
|
|
(5
|
)
|
|
(11
|
)
|
|
(58
|
)
|
|
(74
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
income taxes
|
|
|
659
|
|
|
(22
|
)
|
|
(68
|
)
|
|
569
|
|
Income
tax
expense (benefit)
|
|
|
264
|
|
|
(9
|
)
|
|
(18
|
)
|
|
237
|
|
Net
Income
(Loss)
|
|
$
|
395
|
|
$
|
(13
|
)
|
$
|
(50
|
)
|
$
|
332
|
|
|
|
|
|
Power
|
|
|
|
|
|
Change
Between 3rd Quarter 2006 and
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
3rd
Quarter 2005 Financial Results
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Increase
(Decrease)
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
(216
|
)
|
$
|
214
|
|
$
|
-
|
|
$
|
(2
|
)
|
Other
|
|
|
25
|
|
|
28
|
|
|
(154
|
)
|
|
(101
|
)
|
Internal
|
|
|
(79
|
)
|
|
-
|
|
|
79
|
|
|
-
|
|
Total
Revenues
|
|
|
(270
|
)
|
|
242
|
|
|
(75
|
)
|
|
(103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
30
|
|
|
-
|
|
|
30
|
|
Other
operating expenses
|
|
|
1
|
|
|
(123
|
)
|
|
(77
|
)
|
|
(199
|
)
|
Provision
for
depreciation
|
|
|
(41
|
)
|
|
41
|
|
|
1
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
(128
|
)
|
|
5
|
|
|
-
|
|
|
(123
|
)
|
Deferral
of
new regulatory assets
|
|
|
40
|
|
|
(68
|
)
|
|
-
|
|
|
(28
|
)
|
General
taxes
|
|
|
(10
|
)
|
|
10
|
|
|
(1
|
)
|
|
(1
|
)
|
Total
Expenses
|
|
|
(138
|
)
|
|
(105
|
)
|
|
(77
|
)
|
|
(320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(132
|
)
|
|
347
|
|
|
2
|
|
|
217
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(16
|
)
|
|
19
|
|
|
(40
|
)
|
|
(37
|
)
|
Interest
expense
|
|
|
(13
|
)
|
|
(46
|
)
|
|
35
|
|
|
(24
|
)
|
Capitalized
interest
|
|
|
(2
|
)
|
|
1
|
|
|
1
|
|
|
-
|
|
Subsidiaries'
preferred stock dividends
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
1
|
|
Total
Other
Income (Expense)
|
|
|
(30
|
)
|
|
(26
|
)
|
|
(4
|
)
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
income taxes
|
|
|
(162
|
)
|
|
321
|
|
|
(2
|
)
|
|
157
|
|
Income
taxes
|
|
|
(64
|
)
|
|
128
|
|
|
(29
|
)
|
|
35
|
|
Net
Income
|
|
$
|
(98
|
)
|
$
|
193
|
|
$
|
27
|
|
$
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Services - Third Quarter 2006 Compared to Third Quarter 2005
Net
income decreased
$98 million (24.8%) to $297 million in the third quarter of 2006
compared to $395 million in the third quarter of 2005, primarily due to
decreased operating revenues partially offset by lower operating
expenses.
Revenues
-
The
decrease in
total revenues by service type is summarized below:
|
|
Three
Months Ended September 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Distribution
services
|
|
$
|
1,124
|
|
$
|
1,340
|
|
$
|
(216
|
)
|
Transmission
services
|
|
|
109
|
|
|
117
|
|
|
(8
|
)
|
Internal
lease
revenues
|
|
|
-
|
|
|
79
|
|
|
(79
|
)
|
Other
|
|
|
57
|
|
|
24
|
|
|
33
|
|
Total
Revenues
|
|
$
|
1,290
|
|
$
|
1,560
|
|
$
|
(270
|
)
|
Decreases
in
distribution deliveries by customer class are summarized in the following
table:
Electric
Distribution Deliveries
|
|
|
Residential
|
|
(4.9
|
)%
|
Commercial
|
|
(1.0
|
)%
|
Industrial
|
|
(0.6
|
)%
|
Total
Distribution Deliveries
|
|
(2.3
|
)%
|
The
completion of
the Ohio Companies' generation transition cost recovery under their respective
transition plans and Penn's transition plan in 2005 were the primary reasons
for
lower distribution unit prices, which, in conjunction with lower KWH deliveries,
resulted in lower distribution delivery revenues. The decrease in deliveries
to
customers was primarily due to milder weather during the third quarter of 2006
as compared to the same period in 2005. The following table summarizes major
factors contributing to the $216 million decrease in distribution service
revenues in the third quarter of 2006:
Sources
of Change in Distribution Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Changes
in
customer usage
|
|
$
|
(70
|
)
|
Ohio
shopping
incentives
|
|
|
77
|
|
Reduced
Ohio
transition rates
|
|
|
(244
|
)
|
Other
|
|
|
21
|
|
|
|
|
|
|
Net
Decrease
in Distribution Revenues
|
|
$
|
(216
|
)
|
The
decrease in
internal lease revenues resulted from the generation asset transfers discussed
above. The 2005 generation assets lease revenue from affiliates ceased as a
result of the transfers.
Expenses-
The
decrease in
revenues discussed above was partially offset by the following decreases in
total expenses:
|
·
|
Lower
depreciation expense of $41 million that resulted from the generation
asset transfers;
|
|
·
|
Reduced
amortization of regulatory assets of $128 million principally due to
the completion of Ohio generation transition cost recovery and Penn's
transition plan in 2005; and
|
|
·
|
Decreased
general taxes of $10 million
primarily due to lower property taxes as a result of the generation
asset
transfers.
|
Those
decreases in
expenses were partially offset by the following:
· |
Other
operating expenses were $1 million higher in 2006 due, in part, to
the following factors:
|
- |
The
absence in
2006 of expenses for ancillary service refunds to third-parties of
$9 million in 2005 due to the RCP, which provides that alternate
suppliers of ancillary services now bill customers directly for those
services;
|
- |
A
$10 million decrease in employee and contractor costs resulting from
reduced employee benefits (principally postretirement benefits) and
the
decreased use of outside contractors for tree trimming, reliability
work,
legal services and jobbing and contracting;
and
|
- |
An
$18 million increase due, in part, to regulatory fees, costs for
jobbing and contracting and the absence in 2006 of an insurance
settlement.
|
· |
The
deferral
of new regulatory assets was lower as a result of the end of shopping
incentive deferrals under the Ohio Companies’ transition plan, partially
offset by the distribution cost deferrals under the Ohio Companies’
RCP.
|
Other
Income
-
Lower investment income reflects the impact of the generation asset transfers.
The reduction in 2006 of the nuclear decommissioning trust income, the majority
of which is now included in the power supply management services segment, was
partially offset by interest income on the affiliated company notes receivable
from the power supply management services segment in the third quarter of
2006.
The $13 million increase in interest expense in the third quarter of 2006,
compared with the same period of 2005, represents an additional $10 million
of interest expense from OE’s June 2006 issuance of $600 million of
unsecured senior notes. As discussed under Capital Resources and Liquidity,
OE
used the debt proceeds to repurchase $500 million of its common stock from
FirstEnergy, who then redeemed $400 million of FirstEnergy notes in July
2006. This represents a part of FirstEnergy’s 2006 refinancing strategy to
obtain additional financing flexibility at the holding company (represented
in
the Other and Reconciling Adjustment segment) and to capitalize the regulated
utilities more appropriately from a regulatory context.
Power
Supply Management Services - Third Quarter 2006 Compared to Third Quarter
2005
Net
income for this
segment was $180 million in the third quarter of 2006 compared to a net
loss of $13 million in the same period last year. An improvement in the
gross generation margin and increased transmission and fuel cost deferrals
was
partially offset by higher depreciation, general taxes and interest expense
resulting from the generation asset transfers.
Revenues
-
Electric generation sales revenues increased $185 million in the third
quarter of 2006 compared to the same period in 2005. This increase primarily
resulted from a 7.7% increase in retail KWH sales, mostly due to the return
of
customers as a result of third-party suppliers leaving the northern Ohio
marketplace and higher unit prices resulting from the 2006 rate stabilization
and fuel recovery charges. The higher retail sales reduced energy available
for
sale to the wholesale market. Increased transmission revenues resulted primarily
from new revenues of approximately $34 million under the MISO transmission
rider that began in the first quarter of 2006 and revenue increases from auction
revenue rights and financial transmission rights.
An
increase in
reported segment revenues resulted from the following sources:
|
|
Three
Months Ended September 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Electric
Generation Sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
1,640
|
|
$
|
1,254
|
|
$
|
386
|
|
Wholesale
|
|
|
229
|
|
|
430
|
|
|
(201
|
)
|
Total
Electric
Generation Sales
|
|
|
1,869
|
|
|
1,684
|
|
|
185
|
|
Transmission
|
|
|
182
|
|
|
110
|
|
|
72
|
|
Other
|
|
|
15
|
|
|
30
|
|
|
(15
|
)
|
Total
Revenues
|
|
$
|
2,066
|
|
$
|
1,824
|
|
$
|
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 7.7%
increase in customer usage
|
|
$
|
97
|
|
Increased
prices
|
|
|
289
|
|
|
|
|
386
|
|
Wholesale:
|
|
|
|
|
Effect
of
32.9% decrease in KWH sales
|
|
|
(141
|
)
|
Lower
prices
|
|
|
(60
|
)
|
|
|
|
(201
|
)
|
Net
Increase
in Electric Generation Sales
|
|
$
|
185
|
|
Expenses
-
Total
operating
expenses decreased by $105 million.
The
decrease was due to the following factors:
|
·
|
Lower
non-fuel
operating expenses of $123 million reflect the absence in 2006 of
generating lease rents ($79 million paid in 2005) due to the
generation asset transfers and decreases in fossil production and
transmission expenses of $20 million and $21 million,
respectively, partially offset by higher nuclear operating expenses
of
$9 million. The lower fossil production expenses reflected higher
credits of $24 million in 2006 from emission allowance sales compared
to the same period of 2005. Decreased transmission expenses reflected
lower congestion costs. Nuclear operating costs were higher principally
due to preparation costs related to the Beaver Valley Unit 2 outage
that
began on October 2, 2006 and increased labor and benefit costs;
and
|
|
·
|
A
$68 million increase in the deferral of new regulatory assets
primarily related to the Ohio RCP fuel deferral of $43 million in
2006. The increase also reflected PJM/MISO costs incurred that are
expected to be recovered from customers through future rates. The
recognition of these amounts under the Power Supply Management Services
segment reflects a change in the current year operations reporting
as
discussed in Note 13 - Segment Information. Retail transmission revenues
and PJM/MISO transmission revenues and expenses associated with serving
electricity load are now included in the power supply management
services
segment results.
|
The
above expense
decreases were partially offset by the following:
|
·
|
Higher
fuel
costs of $8 million, primarily coal cost increases resulting from
higher coal commodity prices and increased transportation costs for
western coal. The increased coal costs were partially offset by decreased
generation output and lower natural gas and emission allowance costs
of
$20 million. Purchased power costs increased $22 million
due to
higher prices and were partially offset by lower volumes. Factors
producing 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
|
|
$
|
12
|
|
Change
due to
volume consumed
|
|
|
(4
|
)
|
|
|
|
8
|
|
Purchased
Power:
|
|
|
|
|
Change
due to
increased unit costs
|
|
|
68
|
|
Change
due to
volume purchased
|
|
|
(32
|
)
|
PPUC
NUG
adjustment applicable to prior year
|
|
|
10
|
|
Increase
in
NUG costs deferred
|
|
|
(24
|
)
|
|
|
|
22
|
|
|
|
|
|
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
$
|
30
|
|
|
·
|
Increased
depreciation expenses of $41 million resulted principally from the
generation asset transfers; and
|
|
·
|
Higher
general
taxes of $10 million due to additional property taxes resulting from
the generation asset transfers.
|
Other
Income and
Expense -
·
|
Investment
income in the third quarter of 2006 increased by $19 million over the
prior year primarily due to nuclear decommissioning trust investments
acquired through the generation asset transfers;
and
|
|
|
·
|
Interest
expense increased by $46 million in the third quarter of 2006 primarily
due to the interest expense on associated company notes payable that
financed the generation asset transfers.
|
Other
-
Third Quarter 2006 Compared to Third 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 a $27 million increase to FirstEnergy’s net
income in the third quarter of 2006 compared to the same quarter of 2005. The
increase was primarily due to a $5 million improvement in gas commodity
transactions, a $3 million increase in insurance investment income and
$15 million of income tax benefits, primarily reflecting the 2005 federal
income tax return filed in the third quarter of 2006.
Summary
of
Results of Operations - First Nine Months of 2006 Compared with the First Nine
Months of 2005
Financial
results
for FirstEnergy's major business segments in the first nine months of 2006
and
2005 were as follows:
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Nine Months of 2006 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
2,972
|
|
$
|
5,207
|
|
$
|
-
|
|
$
|
8,179
|
|
Other
|
|
|
445
|
|
|
157
|
|
|
250
|
|
|
852
|
|
Internal
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
Revenues
|
|
|
3,417
|
|
|
5,364
|
|
|
250
|
|
|
9,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
3,306
|
|
|
-
|
|
|
3,306
|
|
Other
operating expenses
|
|
|
921
|
|
|
1,270
|
|
|
255
|
|
|
2,446
|
|
Provision
for
depreciation
|
|
|
279
|
|
|
146
|
|
|
20
|
|
|
445
|
|
Amortization
of regulatory assets
|
|
|
650
|
|
|
15
|
|
|
-
|
|
|
665
|
|
Deferral
of
new regulatory assets
|
|
|
(164
|
)
|
|
(215
|
)
|
|
-
|
|
|
(379
|
)
|
General
taxes
|
|
|
409
|
|
|
127
|
|
|
17
|
|
|
553
|
|
Total
Expenses
|
|
|
2,095
|
|
|
4,649
|
|
|
292
|
|
|
7,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
1,322
|
|
|
715
|
|
|
(42
|
)
|
|
1,995
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
204
|
|
|
36
|
|
|
(120
|
)
|
|
120
|
|
Interest
expense
|
|
|
(293
|
)
|
|
(168
|
)
|
|
(67
|
)
|
|
(528
|
)
|
Capitalized
interest
|
|
|
12
|
|
|
8
|
|
|
1
|
|
|
21
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(10
|
)
|
|
-
|
|
|
4
|
|
|
(6
|
)
|
Total
Other
Income (Expense)
|
|
|
(87
|
)
|
|
(124
|
)
|
|
(182
|
)
|
|
(393
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
income taxes and discontinued operations
|
|
|
1,235
|
|
|
591
|
|
|
(224
|
)
|
|
1,602
|
|
Income
tax
expense (benefit)
|
|
|
499
|
|
|
236
|
|
|
(112
|
)
|
|
623
|
|
Income
before
discontinued operations
|
|
|
736
|
|
|
355
|
|
|
(112
|
)
|
|
979
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
Income
(Loss)
|
|
$
|
736
|
|
$
|
355
|
|
$
|
(112
|
)
|
$
|
979
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Nine Months of 2005 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
3,509
|
|
$
|
4,523
|
|
$
|
-
|
|
$
|
8,032
|
|
Other
|
|
|
414
|
|
|
94
|
|
|
557
|
|
|
1,065
|
|
Internal
|
|
|
238
|
|
|
-
|
|
|
(238
|
)
|
|
-
|
|
Total
Revenues
|
|
|
4,161
|
|
|
4,617
|
|
|
319
|
|
|
9,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
3,115
|
|
|
-
|
|
|
3,115
|
|
Other
operating expenses
|
|
|
963
|
|
|
1,505
|
|
|
282
|
|
|
2,750
|
|
Provision
for
depreciation
|
|
|
398
|
|
|
26
|
|
|
20
|
|
|
444
|
|
Amortization
of regulatory assets
|
|
|
983
|
|
|
-
|
|
|
-
|
|
|
983
|
|
Deferral
of
new regulatory assets
|
|
|
(253
|
)
|
|
(52
|
)
|
|
-
|
|
|
(305
|
)
|
General
taxes
|
|
|
423
|
|
|
101
|
|
|
17
|
|
|
541
|
|
Total
Expenses
|
|
|
2,514
|
|
|
4,695
|
|
|
319
|
|
|
7,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
1,647
|
|
|
(78
|
)
|
|
-
|
|
|
1,569
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
171
|
|
|
-
|
|
|
-
|
|
|
171
|
|
Interest
expense
|
|
|
(285
|
)
|
|
(28
|
)
|
|
(175
|
)
|
|
(488
|
)
|
Capitalized
interest
|
|
|
13
|
|
|
(1
|
)
|
|
-
|
|
|
12
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(13
|
)
|
|
-
|
|
|
-
|
|
|
(13
|
)
|
Total
Other
Income (Expense)
|
|
|
(114
|
)
|
|
(29
|
)
|
|
(175
|
)
|
|
(318
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
income taxes and discontinued operations
|
|
|
1,533
|
|
|
(107
|
)
|
|
(175
|
)
|
|
1,251
|
|
Income
tax
expense (benefit)
|
|
|
613
|
|
|
(43
|
)
|
|
29
|
|
|
599
|
|
Income
before
discontinued operations
|
|
|
920
|
|
|
(64
|
)
|
|
(204
|
)
|
|
652
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
18
|
|
|
18
|
|
Net
Income
(Loss)
|
|
$
|
920
|
|
$
|
(64
|
)
|
$
|
(186
|
)
|
$
|
670
|
|
|
|
|
|
Power
|
|
|
|
|
|
Change
Between First Nine Months of 2006
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
and
First Nine Months of 2005
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Financial
Results -
Increase (Decrease)
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
(537
|
)
|
$
|
684
|
|
$
|
-
|
|
$
|
147
|
|
Other
|
|
|
31
|
|
|
63
|
|
|
(307
|
)
|
|
(213
|
)
|
Internal
|
|
|
(238
|
)
|
|
-
|
|
|
238
|
|
|
-
|
|
Total
Revenues
|
|
|
(744
|
)
|
|
747
|
|
|
(69
|
)
|
|
(66
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
191
|
|
|
-
|
|
|
191
|
|
Other
operating expenses
|
|
|
(42
|
)
|
|
(235
|
)
|
|
(27
|
)
|
|
(304
|
)
|
Provision
for
depreciation
|
|
|
(119
|
)
|
|
120
|
|
|
-
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
(333
|
)
|
|
15
|
|
|
-
|
|
|
(318
|
)
|
Deferral
of
new regulatory assets
|
|
|
89
|
|
|
(163
|
)
|
|
-
|
|
|
(74
|
)
|
General
taxes
|
|
|
(14
|
)
|
|
26
|
|
|
-
|
|
|
12
|
|
Total
Expenses
|
|
|
(419
|
)
|
|
(46
|
)
|
|
(27
|
)
|
|
(492
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(325
|
)
|
|
793
|
|
|
(42
|
)
|
|
426
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
33
|
|
|
36
|
|
|
(120
|
)
|
|
(51
|
)
|
Interest
expense
|
|
|
(8
|
)
|
|
(140
|
)
|
|
108
|
|
|
(40
|
)
|
Capitalized
interest
|
|
|
(1
|
)
|
|
9
|
|
|
1
|
|
|
9
|
|
Subsidiaries'
preferred stock dividends
|
|
|
3
|
|
|
-
|
|
|
4
|
|
|
7
|
|
Total
Other
Income (Expense)
|
|
|
27
|
|
|
(95
|
)
|
|
(7
|
)
|
|
(75
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
income taxes and discontinued operations
|
|
|
(298
|
)
|
|
698
|
|
|
(49
|
)
|
|
351
|
|
Income
taxes
|
|
|
(114
|
)
|
|
279
|
|
|
(141
|
)
|
|
24
|
|
Income
before
discontinued operations
|
|
|
(184
|
)
|
|
419
|
|
|
92
|
|
|
327
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
(18
|
)
|
|
(18
|
)
|
Net
Income
|
|
$
|
(184
|
)
|
$
|
419
|
|
$
|
74
|
|
$
|
309
|
|
Regulated
Services - First Nine Months of 2006 Compared to First Nine Months of 2005
Net
income decreased
$184 million (20.0%) to $736 million in the first nine months of 2006
compared to $920 million in the first nine months of 2005, primarily due to
decreased operating revenues partially offset by lower operating
expenses.
Revenues
-
The
decrease in
total revenues by service type is summarized below:
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Distribution
services
|
|
$
|
2,972
|
|
$
|
3,509
|
|
$
|
(537
|
)
|
Transmission
services
|
|
|
290
|
|
|
314
|
|
|
(24
|
)
|
Internal
lease
revenues
|
|
|
-
|
|
|
238
|
|
|
(238
|
)
|
Other
|
|
|
155
|
|
|
100
|
|
|
55
|
|
Total
Revenues
|
|
$
|
3,417
|
|
$
|
4,161
|
|
$
|
(744
|
)
|
Decreases
in
distribution deliveries by customer class are summarized in the following
table:
Electric
Distribution Deliveries
|
|
|
|
Residential
|
|
|
(4.1
|
)%
|
Commercial
|
|
|
(1.4
|
)%
|
Industrial
|
|
|
(1.0
|
)%
|
Total
Distribution Deliveries
|
|
|
(2.2
|
)%
|
The
completion of
the Ohio Companies' generation transition cost recovery under their respective
transition plans and Penn's transition plan in 2005 were the primary reasons
for
lower distribution unit prices, which, in conjunction with lower KWH deliveries,
resulted in lower distribution delivery revenues. The decreases in deliveries
to
customers were primarily due to milder weather during the first nine months
of
2006 as compared to the same period in 2005. The following table summarizes
major factors contributing to the $537 million decrease in distribution
service revenues in the first nine months of 2006:
Sources
of Change in Distribution Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Changes
in
customer usage
|
|
$
|
(173
|
)
|
Ohio
shopping
incentives
|
|
|
178
|
|
Reduced
Ohio
transition rates
|
|
|
(614
|
)
|
Other
|
|
|
72
|
|
|
|
|
|
|
Net
Decrease
in Distribution Revenues
|
|
$
|
(537
|
)
|
The
decrease in
internal lease 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. The increase in other revenues is due to higher
payments received during the first quarter of 2006 under a contract provision
associated with the prior sale of TMI, a 2006 uranium enrichment settlement
and
increased income on life insurance investments.
Expenses-
The
decrease in
revenues discussed above was partially offset by the following decreases in
total expenses:
|
·
|
Other
operating expenses were $42 million lower in 2006 due, in part, to
the following factors:
|
- |
The
absence in
2006 of expenses for ancillary service refunds to third parties of
$22 million in 2005 due to the RCP, which provides that alternate
suppliers of ancillary services now bill customers directly for those
services;
|
- |
A
$43 million decrease in employee and contractor costs resulting from
lower storm-related expenses, reduced employee benefits and the decreased
use of outside contractors for tree trimming, reliability work, legal
services and jobbing and contracting;
and
|
- |
A
$22 million increase in other expenses due, in part, to the absence
in 2006 of a $6 million insurance premium credit and a
$3.4 million insurance settlement received in
2005.
|
|
·
|
Lower
depreciation expense of $119 million resulted from the generation
asset
transfers;
|
|
·
|
Reduced
amortization of regulatory assets of $333 million resulted
principally from the completion of Ohio generation transition cost
recovery and Penn's transition plan in 2005;
and
|
|
·
|
General
taxes
decreased by $14 million primarily due to lower property taxes as a
result of the generation asset
transfers.
|
The
reduction in the
deferral of new regulatory assets resulted from last year’s JCP&L rate
decision and the end of shopping incentive deferrals under the Ohio Companies’
transition plan, partially offset by the distribution cost deferrals under
the
Ohio Companies’ RCP.
Other
Income and
Expense -
|
·
|
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 nine months of 2006
is
partially offset by the absence of nuclear decommissioning trust
investments, the majority of which is now included in the power supply
management services segment; and
|
|
·
|
Interest
expense increased by $8 million due to the June 2006 issuance of
$600 million of OE long-term debt, which reflects FirstEnergy’s
financing strategy as discussed in the third quarter results analysis.
Subsidiaries' preferred stock dividends decreased by $3 million in
2006
due to redemption activity since the third quarter of
2005.
|
Power
Supply Management Services - First Nine Months of 2006 Compared to First Nine
Months of 2005
Net
income for this
segment was $355 million in the first nine months of 2006 compared to a net
loss of $64 million in the same period last year. An improvement in the
gross generation margin and increased transmission and fuel costs deferrals
was
partially offset by higher depreciation, general taxes and interest expense
resulting from the generation asset transfers.
Revenues
-
Electric generation sales revenues increased $608 million in the first nine
months of 2006 compared to the same period in 2005. This increase primarily
resulted from a 7.4% increase in retail KWH sales, mostly due to the return
of
customers as a result of third-party suppliers leaving the northern Ohio
marketplace and higher unit prices resulting from the 2006 rate stabilization
and fuel recovery charges. The higher retail sales reduced energy available
for
sale to the wholesale market. Increased transmission revenues reflected new
revenues of approximately $88 million under the MISO transmission rider
that began in the first quarter of 2006. These increases were partially offset
by a reduction in wholesale sales revenue as a result of both lower KWH sales
and lower unit prices.
The
increase in
reported segment revenues resulted from the following sources:
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Electric
Generation Sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
4,164
|
|
$
|
3,223
|
|
$
|
941
|
|
Wholesale
|
|
|
717
|
|
|
1,050
|
|
|
(333
|
)
|
Total
Electric
Generation Sales
|
|
|
4,881
|
|
|
4,273
|
|
|
608
|
|
Transmission
|
|
|
444
|
|
|
292
|
|
|
152
|
|
Other
|
|
|
39
|
|
|
52
|
|
|
(13
|
)
|
Total
Revenues
|
|
$
|
5,364
|
|
$
|
4,617
|
|
$
|
747
|
|
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 7.4%
increase in customer usage
|
|
$
|
238
|
|
Change
in
prices
|
|
|
703
|
|
|
|
|
941
|
|
Wholesale:
|
|
|
|
|
Effect
of
19.6% decrease in KWH sales
|
|
|
(205
|
)
|
Change
in
prices
|
|
|
(128
|
)
|
|
|
|
(333
|
)
|
Net
Increase
in Electric Generation Sales
|
|
$
|
608
|
|
Expenses
-
Total
operating
expenses decreased by $46 million.
The
decrease was due to the following factors:
· Lower
non-fuel
operating expenses of $235 million, which reflect the absence in 2006 of
generating asset lease rents of $238 million charged in 2005 due to the
generation asset transfers and the emission allowance sales credits discussed
above in the third quarter results analysis. Also absent in 2006 were 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 New Source Review settlement, and a $3.5 million penalty
related to the Davis-Besse outage. These decreases were partially offset by
increases in nuclear operating expenses of $9 million as discussed in the
third quarter results analysis above and transmission expenses of
$19 million; and
· An
increase of
$163 million in the deferral of new regulatory assets, which consisted of
PJM/MISO costs incurred that are expected to be recovered from customers through
future rates and the Ohio RCP fuel deferral and related interest of
$94 million.
The
above decreases
in expenses were partially offset by:
|
·
|
Higher
fuel
and purchased power costs of $191 million, including increased fuel
costs of $80 million. In particular, coal costs increased
$107 million as a result of increased generation output, higher coal
commodity prices and increased transportation costs for western coal.
The
increased coal costs were partially offset by lower natural gas and
emission allowance costs of $36 million. Purchased power costs
increased $111 million due to higher prices partially offset by lower
volumes. 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
|
|
$
|
46
|
|
Change
due to
volume consumed
|
|
|
34
|
|
|
|
|
80
|
|
Purchased
Power:
|
|
|
|
|
Change
due to
increased unit costs
|
|
|
197
|
|
Change
due to
volume purchased
|
|
|
(62
|
)
|
PPUC
NUG
adjustment applicable to prior year
|
|
|
10
|
|
Increase
in
NUG costs deferred
|
|
|
(34
|
)
|
|
|
|
111
|
|
|
|
|
|
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
$
|
191
|
|
|
·
|
Increased
depreciation expenses of $120 million, resulting principally from the
generation asset transfers; and
|
|
·
|
Higher
general taxes of $26 million due to additional property taxes
resulting from the generation asset transfers.
|
Other
Income and
Expense -
·
|
Investment
income in the first nine months of 2006 was $36 million higher
primarily due to nuclear decommissioning trust investments acquired
through the generation asset transfers; and
|
|
|
·
|
Interest
expense increased by $140 million, primarily due to interest on the
associated company notes payable that financed the generation asset
transfers. This increase was partially offset by an additional
$9 million of capitalized
interest.
|
Other
-
First Nine Months of 2006 Compared to First Nine Months of
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 a $74 million increase to FirstEnergy’s net
income in the first nine months of 2006 compared to the same period of 2005.
The
increase was primarily due to the absence of last year’s write-off of income tax
benefits of $71 million due to the 2005 change in Ohio tax legislation, the
2006 income taxes benefits described in the Other - Third Quarter 2006 compared
to Third Quarter 2005 results analysis above, a $3 million gain related to
interest rate swap financing arrangements and a $6 million increase in
insurance investment income in the first nine months of 2006. These increases
were partially offset by the 2006 non-core assets sale and impairment charges
of
$10 million and the absence of the after-tax gains of $17 million from
discontinued operations in 2005 (see Note 4). The following table summarizes
the
sources of income from discontinued operations (in millions) for the nine months
ended September 30, 2005:
Discontinued
Operations (Net of tax)
|
|
|
|
Gain
on
sale:
|
|
|
|
Natural
gas
business
|
|
$
|
5
|
|
Elliot-Lewis,
Spectrum and Power Piping
|
|
|
12
|
|
Reclassification
of operating income
|
|
|
1
|
|
Total
|
|
$
|
18
|
|
CAPITAL
RESOURCES AND LIQUIDITY
FirstEnergy expects to meet its future 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 $2.75 billion of short-term financing under a revolving
credit facility which expires in 2011, 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 the facility.
In July 2006, FirstEnergy redeemed $400 million of its outstanding senior notes
that were due to mature in November 2006 using cash proceeds from OE’s
repurchase of $500 million of common stock.
In
August 2006, FirstEnergy repurchased 10.6 million shares, or approximately
3.2%,
of its outstanding common stock at an initial purchase price of $600 million,
pursuant to an accelerated share repurchase program. The repurchase was funded
with borrowings from FirstEnergy’s revolving credit facility.
As of September 30, 2006, FirstEnergy had $41 million of cash and cash
equivalents compared with $64 million as of December 31, 2005. The
major sources of changes in cash and cash equivalent 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
$1.2 billion and $1.9 billion in the first nine months of 2006 and 2005,
respectively, and is summarized as follows:
|
|
Nine
Months Ended
|
|
|
September
30,
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
(In
millions)
|
Cash
earnings
*
|
|
$
1,472
|
|
$
1,572
|
Working
capital and other
|
|
(229
|
) |
344
|
Net
cash
provided from operating activities
|
|
$
1,243
|
|
$
1,916
|
|
|
|
|
|
*
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 is a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. Generally, a Non-GAAP financial
measure is a numerical measure of a company’s historical or future financial
performance, financial position, or cash flows that either excludes or includes
amounts, or is subject to adjustment that has the effect of excluding or
including amounts, that are not normally excluded or included in the most
directly comparable measure calculated and presented in accordance with GAAP.
Earnings before unusual items on a Non-GAAP basis (normalized earnings) are
not
calculated in accordance with GAAP because they exclude the impact of “unusual
items.” Unusual items reflect the impact on earnings of material events that are
not routine, including those that may be related to discontinued businesses
or
the cumulative effect of an accounting change. Management believes presenting
normalized earnings calculated in this manner provides useful information to
investors in evaluating the ongoing results of FirstEnergy’s businesses and
assists investors in comparing the company’s operating performance to the
operating performance of other companies in the energy sector. In addition,
cash
earnings (Non-GAAP) are not defined under GAAP. Management believes presenting
this Non-GAAP measure provides useful information to investors in assessing
FirstEnergy’s operating performance from a cash perspective without the effects
of material unusual economic events. FirstEnergy’s management frequently
references these Non-GAAP financial measures in its decision-making, using
them
to facilitate historical and ongoing performance comparisons as well as
comparisons to the performance of peer companies. These Non-GAAP measures should
be considered in addition to, and not as a substitute for, their most directly
comparable financial measures prepared in accordance with GAAP.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
979
|
|
$
|
670
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
445
|
|
|
444
|
|
Amortization
of regulatory assets
|
|
|
665
|
|
|
983
|
|
Deferral
of
new regulatory assets
|
|
|
(379
|
)
|
|
(305
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
67
|
|
|
63
|
|
Deferred
purchased power and other costs
|
|
|
(323
|
)
|
|
(258
|
)
|
Deferred
income taxes and investment tax credits
|
|
|
36
|
|
|
24
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(54
|
)
|
|
(71
|
)
|
Accrued
compensation and retirement benefits
|
|
|
78
|
|
|
72
|
|
Gain
on asset
sales
|
|
|
(38
|
)
|
|
-
|
|
Income
from
discontinued operations
|
|
|
-
|
|
|
(18
|
)
|
Other
non-cash
expenses
|
|
|
(4
|
)
|
|
(32
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
1,472
|
|
$
|
1,572
|
|
|
|
|
|
|
|
|
|
Net
cash provided
from operating activities decreased by $673 million in the first nine
months of 2006 compared to the first nine months of 2005 primarily due to a
$573 million decrease from working capital and a $100 million decrease
in cash earnings described under "Results of Operations." The decrease from
working capital changes primarily resulted from $242 million of funds
received in 2005 for prepaid electric service (under a three-year Energy for
Education Program with the Ohio Schools Council), increased outflows of
$153 million for payables primarily caused by higher fuel and purchased
power costs, increased tax payments of $242 million, and $147 million
of cash collateral returned to suppliers. These decreases were partially offset
by an increase in cash provided from the collection of receivables of $219
million, reflecting increased electric sales revenues.
Cash
Flows From Financing Activities
In
the nine months
ended September 30, 2006, cash used for financing activities was $444 million
compared to $1.0 billion in the same period of 2005. The following table
summarizes security issuances and redemptions.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Securities
Issued or Redeemed
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
New
issues
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
253
|
|
$
|
334
|
|
Secured
notes
|
|
|
382
|
|
|
-
|
|
Unsecured
notes
|
|
|
600
|
|
|
-
|
|
|
|
$
|
1,235
|
|
$
|
334
|
|
Redemptions
|
|
|
|
|
|
|
|
First
mortgage
bonds
|
|
$
|
-
|
|
$
|
178
|
|
Pollution
control notes
|
|
|
311
|
|
|
377
|
|
Secured
notes
|
|
|
182
|
|
|
74
|
|
Unsecured
notes
|
|
|
500
|
|
|
8
|
|
Long-term
revolving credit
|
|
|
-
|
|
|
215
|
|
Common
stock
|
|
|
600
|
|
|
-
|
|
Preferred
stock
|
|
|
107
|
|
|
170
|
|
|
|
$
|
1,700
|
|
$
|
1,022
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
482
|
|
$
|
77
|
|
FirstEnergy
had
approximately $1.2 billion of short-term indebtedness as of September 30,
2006 compared to approximately $731 million as of December 31, 2005.
This increase primarily reflects FirstEnergy’s use of short-term debt to fund
its $600 million common share repurchase in August 2006. Available bank
borrowing capability (in millions) as of September 30, 2006 included the
following:
Borrowing
Capability
|
|
|
|
Short-term
credit facilities(1)
|
|
$
|
2,870
|
|
Accounts
receivable financing facilities
|
|
|
550
|
|
Utilized
|
|
|
(1,207
|
)
|
LOCs
|
|
|
(85
|
)
|
Net
|
|
$
|
2,128
|
|
|
|
|
|
|
(1)
A $2.75
billion revolving credit facility that expires in 2011 is available
in
various amounts to FirstEnergy and certain of its subsidiaries, as
described further below. A $100 million revolving credit facility
that
expires in December 2006 and a $20 million uncommitted line of credit
facility are both available to FirstEnergy
only.
|
As of September 30, 2006, the Ohio Companies and Penn had the aggregate
capability to issue approximately $1.5 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 $655 million
and $579 million, respectively, as of September 30, 2006. Under the
provisions of its senior note indenture, JCP&L may issue additional FMB only
as collateral for senior notes. As of September 30, 2006, JCP&L had the
capability to issue $626 million of additional senior notes upon the basis
of FMB collateral.
Based upon applicable earnings coverage tests in their respective charters,
Penn, TE and JCP&L could issue a total of $2.5 billion of preferred
stock (assuming no additional debt was issued) as of September 30, 2006.
CEI, Met-Ed and Penelec do not have similar restrictions and could issue up
to
the number of preferred shares authorized under their respective charters.
As a
result of OE redeeming all of its outstanding preferred stock in July 2006,
the applicable earnings coverage test in its charter is inoperative. In the
event that OE issues preferred stock in the future, the applicable earnings
coverage test will govern the amount of preferred stock that OE may
issue.
As of September 30, 2006, approximately $1.0 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 September 30, 2006, OE had
approximately $400 million of capacity remaining unused under its existing
shelf registration for unsecured debt securities. Shelf registration
statements for unsecured debt securities for CEI of $550 million and TE of
$300 million were declared effective by the SEC on October 31, 2006
and remain unused.
On August 24, 2006, FirstEnergy and certain of its subsidiaries entered into
a
new $2.75 billion five-year revolving credit facility (included in the borrowing
capability table above), which replaced FirstEnergy’s prior $2 billion credit
facility. FirstEnergy
may
request an increase in the total commitments available under the new facility
up
to a maximum of $3.25 billion. Commitments under the new facility are
available until August 24, 2011, unless the lenders agree, at the request
of the Borrowers, to two additional one-year extensions. Generally, borrowings
under the facility must be repaid within 364 days. Available amounts for each
Borrower are subject to a specified sub-limit, as well as applicable regulatory
and other limitations.
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
Limitations(1)
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
$
|
2,750
|
|
$
|
1,500
|
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
44
|
|
CEI
|
|
|
250
|
(3)
|
|
600
|
|
TE
|
|
|
250
|
(3)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
429
|
|
Met-Ed
|
|
|
250
|
|
|
250
|
(2)
|
Penelec
|
|
|
250
|
|
|
250
|
(2)
|
FES
|
|
|
-
|
(4)
|
|
n/a
|
|
ATSI
|
|
|
-
|
(4)
|
|
50
|
|
|
(1)
|
As
of
September 30, 2006.
|
|
(2)
|
Excluding
amounts which may be borrowed under the regulated money
pool.
|
|
(3)
|
Borrowing
sub-limits for CEI and TE may be increased to up to $500 million by
delivering notice to the administrative agent that such borrower
has
senior unsecured debt ratings of at least BBB by S&P and Baa2 by
Moody’s.
|
|
(4)
|
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 ($390 million unused as
of September 30, 2006) of accounts receivable financing facilities for OE,
CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet
working capital and other general corporate 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 $2.1 billion as of September 30,
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
September 30, 2006, FirstEnergy and its subsidiaries' debt to total
capitalization ratios (as defined under the revolving credit facility) were
as
follows:
Borrower
|
|
|
FirstEnergy
|
|
55
|
%
|
OE
|
|
46
|
%
|
Penn
|
|
33
|
%
|
CEI
|
|
49
|
%
|
TE
|
|
30
|
%
|
JCP&L
|
|
23
|
%
|
Met-Ed
|
|
38
|
%
|
Penelec
|
|
35
|
%
|
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 nine months of 2006 was approximately 5.09%
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 October 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
|
|
|
|
|
|
|
|
|
|
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+
|
|
|
|
|
|
|
|
|
|
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,
$106.5 million of pollution control revenue refunding bonds were issued on
behalf of NGC ($60 million at 3.07% and $46.5 million at 3.25%). The
proceeds from the 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%. Also, on April 3, 2006, $146.7 million of
pollution control revenue refunding bonds were issued on behalf of FGCO ($90.1
million at 3.03% and $56.6 million at 3.10%) which were used to redeem, in
April
and May 2006, 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%. These refinancings were undertaken in connection with FirstEnergy's
intra-system generation asset transfers discussed above. 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 pollution control notes.
On May 12, 2006, JCP&L issued $200 million of 6.40% secured senior
notes due 2036. The proceeds of the offering were used to repay at maturity
$150 million aggregate principal amount of JCP&L’s 6.45% senior notes
due May 15, 2006 and for general corporate purposes.
On
June 26,
2006, OE issued $600 million of unsecured senior notes, comprised of $250
million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The
majority of the proceeds from this offering were used in July 2006 to repurchase
$500 million of OE common stock from FirstEnergy, enabling FirstEnergy to
accelerate repayment of $400 million of senior notes that were due to mature
in
November 2006. The remainder of the proceeds were used to redeem approximately
$61 million of OE’s preferred stock on July 7, 2006 and to reduce
short-term borrowings.
On
August 10,
2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L,
issued $182 million of transition bonds with a weighted average interest rate
of
5.5%
to
securitize the recovery of deferred costs associated with JCP&L’s supply of
BGS.
On August 10, 2006, FirstEnergy repurchased 10.6 million shares,
approximately 3.2%, of its outstanding common stock through an accelerated
share
repurchase program. The initial purchase price was $600 million, or $56.44
per share. The final purchase price will be adjusted to reflect the ultimate
cost to acquire the shares over a period of up to seven months. The share
repurchase was completed under a program authorized by the Board of Directors
on
June 20, 2006 to repurchase up to 12 million shares of common stock.
At management’s discretion, additional shares may be acquired under the program
on the open market or through privately negotiated transactions, subject to
market conditions and other factors. The Board’s authorization of the repurchase
program does not require FirstEnergy to make any further purchases of shares
and
the program may be terminated at any time.
FirstEnergy
continues
to pursue its strategy of replacing holding company debt with debt at its
utility operating subsidiaries in order to obtain additional financing
flexibility at the holding company level and capitalize its regulated utilities
in a way that positions them appropriately in a regulatory context.
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 transmission and distribution of electricity. Capital
expenditures by the power supply management services segment are principally
generation-related. The following table summarizes investments for the nine
months ended September 30, 2006 and 2005 by segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(492
|
)
|
$
|
142
|
|
$
|
(8
|
)
|
$
|
(358
|
)
|
Power
supply
management services
|
|
|
(473
|
)
|
|
(7
|
)
|
|
(1
|
)
|
|
(481
|
)
|
Other
|
|
|
(1
|
)
|
|
(2
|
)
|
|
-
|
|
|
(3
|
)
|
Reconciling
items
|
|
|
(24
|
)
|
|
24
|
|
|
20
|
|
|
20
|
|
Total
|
|
$
|
(990
|
)
|
$
|
157
|
|
$
|
11
|
|
$
|
(822
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(506
|
)
|
$
|
(14
|
)
|
$
|
(7
|
)
|
$
|
(527
|
)
|
Power
supply
management services
|
|
|
(226
|
)
|
|
15
|
|
|
-
|
|
|
(211
|
)
|
Other
|
|
|
(6
|
)
|
|
3
|
|
|
(17
|
)
|
|
(20
|
)
|
Reconciling
items
|
|
|
(18
|
)
|
|
(9
|
)
|
|
5
|
|
|
(22
|
)
|
Total
|
|
$
|
(756
|
)
|
$
|
(5
|
)
|
$
|
(19
|
)
|
$
|
(780
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities in the first nine months of 2006
increased by $42 million compared to the first nine months of 2005. The
increase was principally due to a $234 million increase in property
additions which reflects the replacement of the steam generators and reactor
head at Beaver Valley Unit 1, air quality control system expenditures and the
distribution system Accelerated Reliability Improvement Program. The increase
in
property additions was partially offset by a $65 million decrease in net
nuclear decommissioning trust activities due to the completion of the Ohio
Companies' and Penn's transition cost recovery for decommissioning at the end
of
2005 and $88 million from cash investments, primarily from the expiration
of restrictions on an escrow fund and mortgage indenture deposit.
During the last quarter of 2006, capital requirements for property additions
and
capital leases are expected to be approximately $324 million. FirstEnergy
and the Companies have additional requirements of approximately
$648 million 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
approximately $6.8 billion (excluding nuclear fuel), of which
$1.2 billion applies to 2006. Investments for additional nuclear fuel
during the 2006-2010 periods are estimated to be approximately
$885 million, of which approximately $166 million applies to 2006. During
the same period, FirstEnergy's nuclear fuel investments are expected to be
reduced by approximately $598 million and $91 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 September 30, 2006, FirstEnergy's maximum exposure to potential
future payments under outstanding guarantees and other assurances totaled
approximately $3.6 billion, as summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
Exposure
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees of Subsidiaries:
|
|
|
|
Energy
and
Energy-Related Contracts(1)
|
|
$
|
887
|
|
Other(2)
|
|
|
1,094
|
|
|
|
|
1,981
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
147
|
|
LOC(3)(4)
|
|
|
1,434
|
|
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
$
|
3,562
|
|
|
(1)
|
Issued
for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
Issued
for
various terms.
|
|
(3)
|
Includes
$85 million issued for various terms under LOC capacity available
under FirstEnergy’s revolving credit agreement and $730 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
the Perry Nuclear Power Plant 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 credit support
for
subsidiary financings or refinancings of costs related to the acquisition
of, or
improvements to, 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
September 30, 2006, FirstEnergy's maximum exposure under these collateral
provisions was $487 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
September 30, 2006) which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA. The LOC was reduced to $27 million on
October 15, 2006.
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, 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 September 30, 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 FirstEnergy
and its subsidiaries.
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 the power purchase agreements with NUG entities
that
were structured pursuant to the Public Utility Regulatory Policies Act of
1978.
These non-trading contracts had been adjusted to fair value at the end of
each
quarter, with a corresponding regulatory asset recognized for above-market
costs. On April 1, 2006, FirstEnergy elected to apply the normal purchase
and
normal sale exception to certain NUG power purchase agreements having a fair
value of $13 million (included in “Other” in the table below) in accordance
with guidance in DIG C20. The change in the fair value of commodity derivative
contracts related to energy production during the three months and nine months
ended September 30, 2006 is summarized in the following table:
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
September
30, 2006
|
|
September
30, 2006
|
|
of
Commodity Derivative Contracts
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
(In
millions)
|
|
Change
in the Fair Value of
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net liability at beginning of period
|
$
|
(1,081
|
)
|
$
|
(4
|
)
|
$
|
(1,085
|
)
|
$
|
(1,170
|
)
|
$
|
(3
|
)
|
$
|
(1,173
|
)
|
New
contract
value when entered
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
(164
|
)
|
|
(6
|
)
|
|
(170
|
)
|
|
(195
|
)
|
|
(16
|
)
|
|
(211
|
)
|
Change
in
techniques/assumptions
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
85
|
|
|
1
|
|
|
86
|
|
|
218
|
|
|
10
|
|
|
228
|
|
Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(13
|
)
|
|
-
|
|
|
(13
|
)
|
Outstanding
net liability at end of period (1)
|
|
(1,160
|
)
|
|
(9
|
)
|
|
(1,169
|
)
|
|
(1,160
|
)
|
|
(9
|
)
|
|
(1,169
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Liabilities at End of Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
swaps (2)
|
|
-
|
|
|
(32
|
)
|
|
(32
|
)
|
|
-
|
|
|
(32
|
)
|
|
(32
|
)
|
Net
Liabilities - Derivative Contracts
at
End
of Period
|
$
|
(1,160
|
)
|
$
|
(41
|
)
|
$
|
(1,201
|
)
|
$
|
(1,160
|
)
|
$
|
(41
|
)
|
$
|
(1,201
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
3
|
|
$
|
-
|
|
$
|
3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
$
|
-
|
|
$
|
(5
|
)
|
$
|
(5
|
)
|
$
|
-
|
|
$
|
(6
|
)
|
$
|
(6
|
)
|
Regulatory
assets (net)
|
$
|
82
|
|
$
|
-
|
|
$
|
82
|
|
$
|
(23
|
)
|
$
|
-
|
|
$
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes
$1,160 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 September 30, 2006 as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Current-
|
|
|
|
|
|
|
|
Other
assets
|
|
$
|
-
|
|
$
|
10
|
|
$
|
10
|
|
Other
liabilities
|
|
|
(1
|
)
|
|
(20
|
)
|
|
(21
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
|
46
|
|
|
4
|
|
|
50
|
|
Other
noncurrent liabilities
|
|
|
(1,205
|
)
|
|
(35
|
)
|
|
(1,240
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
liabilities
|
|
$
|
(1,160
|
)
|
$
|
(41
|
)
|
$
|
(1,201
|
)
|
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 as of September 30, 2006 are summarized by year 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
|
)
|
Other
external
sources(3)
|
|
|
(57
|
)
|
|
(270
|
)
|
|
(241
|
)
|
|
(191
|
)
|
|
-
|
|
|
-
|
|
|
(759
|
)
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(175
|
)
|
|
(233
|
)
|
|
(408
|
)
|
Total(4)
|
|
$
|
(57
|
)
|
$
|
(272
|
)
|
$
|
(241
|
)
|
$
|
(191
|
)
|
$
|
(175
|
)
|
$
|
(233
|
)
|
$
|
(1,169
|
)
|
(1) For
the last quarter
of 2006.
(2) Exchange
traded.
(3) Broker
quote
sheets.
|
(4)
|
Includes
$1,160 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 September 30, 2006. Based on derivative contracts held as of
September 30, 2006, an adverse 10% change in commodity prices would
decrease net income by approximately $1 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 - designed to protect against the risk of changes in the fair value
of
fixed-rate debt instruments when interest rates decrease. Swap maturities,
call
options, fixed interest rates and interest payment dates match those of the
underlying obligations. During the first nine months 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 term of each respective hedged security as increased interest expense.
As of September 30, 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 6.46%.
|
|
September
30, 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
|
|
$
|
(2
|
)
|
$
|
100
|
|
|
2008
|
|
$
|
(3
|
)
|
|
|
|
50
|
|
|
2010
|
|
|
(1
|
)
|
|
50
|
|
|
2010
|
|
|
-
|
|
|
|
|
-
|
|
|
2011
|
|
|
-
|
|
|
50
|
|
|
2011
|
|
|
-
|
|
|
|
|
300
|
|
|
2013
|
|
|
(7
|
)
|
|
450
|
|
|
2013
|
|
|
(4
|
)
|
|
|
|
150
|
|
|
2015
|
|
|
(10
|
)
|
|
150
|
|
|
2015
|
|
|
(9
|
)
|
|
|
|
-
|
|
|
2016
|
|
|
-
|
|
|
150
|
|
|
2016
|
|
|
-
|
|
|
|
|
50
|
|
|
2025
|
|
|
(2
|
)
|
|
50
|
|
|
2025
|
|
|
(1
|
)
|
|
|
|
100
|
|
|
2031
|
|
|
(7
|
)
|
|
100
|
|
|
2031
|
|
|
(5
|
)
|
|
|
$
|
750
|
|
|
|
|
$
|
(29
|
)
|
$
|
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 nine months of 2006, FirstEnergy revised the tenor and timing of
its
financing plans. During the second quarter, FirstEnergy terminated forward
swaps
with an aggregate notional value of $600 million concurrent with its
subsidiaries issuing long-term debt. FirstEnergy received $41 million in cash
related to the termination. The gain associated with the ineffective portion
of
the terminated hedges ($6 million) was recognized in earnings, with the
remainder to be recognized over the terms of the associated future debt. During
the third quarter, FirstEnergy revised its financing plan related to swaps
with
$100 million notional value. FirstEnergy terminated and revised the forward
swaps and performed an ineffectiveness assessment. FirstEnergy received cash
of
$2 million, all of which was effective and will be recognized in earnings
over the terms of the associated future debt. As of September 30, 2006,
FirstEnergy had outstanding forward swaps with an aggregate notional amount
of
$725 million and an aggregate fair value of ($2) million.
|
|
September
30, 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
|
|
$
|
-
|
|
$
|
25
|
|
|
2015
|
|
$
|
-
|
|
|
|
|
300
|
|
|
2016
|
|
|
(1
|
)
|
|
600
|
|
|
2016
|
|
|
2
|
|
|
|
|
200
|
|
|
2017
|
|
|
(3
|
)
|
|
25
|
|
|
2017
|
|
|
-
|
|
|
|
|
150
|
|
|
2018
|
|
|
1
|
|
|
275
|
|
|
2018
|
|
|
1
|
|
|
|
|
50
|
|
|
2020
|
|
|
1
|
|
|
50
|
|
|
2020
|
|
|
-
|
|
|
|
$
|
725
|
|
|
|
|
$
|
(2
|
)
|
$
|
975
|
|
|
|
|
$
|
3
|
|
Equity
Price Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their market
value of approximately $1.2 billion as of September 30, 2006 and
$1.1 billion as of December 31, 2005. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $117 million reduction
in fair value as of September 30, 2006.
CREDIT
RISK
Credit risk is the risk of an obligor’s failure to meet the terms of an
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 September 30, 2006, the
largest credit concentration with one party (currently rated investment grade)
represented 9.9% 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 September 30,
2006.
OUTLOOK
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 $225 million as of September 30, 2006. The following
table discloses the regulatory assets by company and by source:
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
746
|
|
$
|
775
|
|
$
|
(29
|
)
|
CEI
|
|
|
855
|
|
|
862
|
|
|
(7
|
)
|
TE
|
|
|
256
|
|
|
287
|
|
|
(31
|
)
|
JCP&L
|
|
|
2,178
|
|
|
2,227
|
|
|
(49
|
)
|
Met-Ed
|
|
|
365
|
|
|
310
|
|
|
55
|
|
ATSI
|
|
|
34
|
|
|
25
|
|
|
9
|
|
Total
|
|
$
|
4,434
|
|
$
|
4,486
|
|
$
|
(52
|
)
|
· |
Penn
had net
regulatory liabilities of approximately $64 million as of
September 30, 2006 and $59 million as of December 31, 2005.
Penelec had net regulatory liabilities of approximately $127 million
and $163 million as of September 30, 2006 and December 31, 2005,
respectively. These net regulatory liabilities are included in Other
Non-current Liabilities on the Consolidated Balance Sheets.
|
Regulatory
assets by
source are as follows:
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
3,339
|
|
$
|
3,576
|
|
$
|
(237
|
)
|
Customer
shopping incentives
|
|
|
621
|
|
|
884
|
|
|
(263
|
)
|
Customer
receivables for future income taxes
|
|
|
214
|
|
|
217
|
|
|
(3
|
)
|
Societal
benefits charge
|
|
|
1
|
|
|
29
|
|
|
(28
|
)
|
Loss
on
reacquired debt
|
|
|
40
|
|
|
41
|
|
|
(1
|
)
|
Employee
postretirement benefits costs
|
|
|
49
|
|
|
55
|
|
|
(6
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and
spent fuel
disposal costs
|
|
|
(135
|
)
|
|
(126
|
)
|
|
(9
|
)
|
Asset
removal
costs
|
|
|
(168
|
)
|
|
(365
|
)
|
|
197
|
|
Property
losses and unrecovered plant costs
|
|
|
21
|
|
|
29
|
|
|
(8
|
)
|
MISO/PJM
transmission costs
|
|
|
177
|
|
|
91
|
|
|
86
|
|
Fuel
costs -
RCP
|
|
|
94
|
|
|
-
|
|
|
94
|
|
Distribution
costs - RCP
|
|
|
121
|
|
|
-
|
|
|
121
|
|
JCP&L
reliability costs
|
|
|
16
|
|
|
23
|
|
|
(7
|
)
|
Other
|
|
|
44
|
|
|
32
|
|
|
12
|
|
Total
|
|
$
|
4,434
|
|
$
|
4,486
|
|
$
|
(52
|
)
|
Reliability
Initiatives
FirstEnergy is proceeding with the implementation of the recommendations that
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) 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.
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 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 an SRM
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. The SRM completed his work and issued
his final report to the NJBPU on June 1, 2006. A meeting was held between
JCP&L and the NJBPU on June 29, 2006 to discuss the SRM’s final report.
JCP&L filed a comprehensive response to the NJBPU on July 14, 2006.
JCP&L continues to file compliance reports reflecting activities associated
with the MOU and Stipulation.
EPACT provides for the creation of an ERO to establish and enforce reliability
standards for the bulk power system, subject to FERC’s 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
reliability organizations (regional entities). The new FERC rule referred to
above, further provides for reorganizing regional entities that would replace
the current regional councils and for rearranging their 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. The ERO filing was noticed on April 7, 2006 and comments
and reply comments were filed in May, June and July 2006. On July 20, 2006,
the
FERC certified the NERC as the ERO to implement the provisions of Section 215
of
the Federal Power Act and directed the NERC to make a compliance filing within
90 days addressing such issues as the regional delegation agreements. The NERC
made its compliance filing in October 2006. This filing is pending before the
FERC.
On
April 4, 2006,
NERC also submitted a filing with the FERC seeking approval of mandatory
reliability standards. These reliability standards are based, with some
modifications and additions, on the current NERC Version O reliability
standards. The reliability standards filing was noticed by the FERC on April
18,
2006. In that notice, the FERC announced its intent to issue a Notice of
Proposed Rulemaking on the proposed reliability standards at a future date.
On
May 11, 2006, the FERC staff released a preliminary assessment that cited
many deficiencies in the proposed reliability standards. The NERC and industry
participants filed comments in response to the Staff’s preliminary assessment.
The FERC held a technical conference on the proposed reliability standards
on
July 6, 2006. The FERC issued a Notice of Proposed Rulemaking on the proposed
reliability standards on October 20, 2006. The FERC voted to adopt 83 of
the proposed 107 reliability standards. The FERC asked the NERC to make
technical improvements to 62 of the 83 standards approved. The 24 standards
that
were not adopted remain pending at the FERC awaiting further clarification
and
filings by the NERC and regional entities. The FERC also provided additional
clarification on the proposed application of final standards in the NOPR.
Interested parties will be given the opportunity to comment on the NOPR within
60 days of its publication in the Federal Register. Mandatory reliability
standards are expected to be in place by the summer of 2007. In a separate
order
issued October 24, 2006, the FERC approved NERC’s 2007 budget and business
plan subject to certain compliance filings.
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.
On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security
standards that replaced interim standards put in place in the wake of the
September 11, 2001 terrorist attacks, and thirteen additional reliability
standards. The security standards became effective on June 1, 2006, and the
remaining standards will become effective throughout 2006 and 2007. NERC intends
to file the standards with the FERC and relevant Canadian authorities for
approval, but the cyber security standards were not included in the
October 20, 2006 NOPR.
FirstEnergy believes that it is in compliance with all current NERC reliability
standards. However, based upon a review of the October 20, 2006 NOPR, it
appears 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 their 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
the
PUCO’s 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 the proceeding as well as the associated entries
on
rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
the PUCO's order with respect to the approval of the rate stabilization charge,
approval of the shopping credits, the granting of interest on shopping credit
incentive deferral amounts, and approval of the Ohio Companies’ financial
separation plan. It remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the competitive
marketplace. The RSP contained a provision that permitted the Ohio Companies
to
withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
have
30 days from the final order or decision to provide notice of termination.
On
July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
a
Proceeding on Remand. In their Request, the Ohio Companies provided notice
of
termination to those provisions of the RSP subject to termination, subject
to
being withdrawn, and also set forth a framework for addressing the Supreme
Court
of Ohio’s findings on customer participation, requesting the PUCO to initiate a
proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
resolution to the issues raised by the Supreme Court of Ohio that is acceptable
to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
considered to be null and void. Separately, the OCC and NOAC also submitted
to
the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
by
the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
to
address the Court’s concern. On September 19, 2006, the PUCO issued an
Entry granting the Ohio Companies’ motion for extension of time to file the
remand proposal. The Ohio Companies filed their RSP Remand CBP on
September 29, 2006. No further proceedings have been scheduled at this
time.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
November 4, 2005, the Ohio Companies filed a supplemental stipulation with
the
PUCO, which constituted an additional component of the RCP filed on September
9,
2005. 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.
|
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
|
|
$
|
173
|
|
$
|
96
|
|
$
|
87
|
|
$
|
356
|
|
2007
|
|
|
180
|
|
|
113
|
|
|
90
|
|
|
383
|
|
2008
|
|
|
207
|
|
|
130
|
|
|
112
|
|
|
449
|
|
2009
|
|
|
-
|
|
|
211
|
|
|
-
|
|
|
211
|
|
2010
|
|
|
-
|
|
|
264
|
|
|
-
|
|
|
264
|
|
Total
Amortization
|
|
$
|
560
|
|
$
|
814
|
|
$
|
289
|
|
$
|
1,663
|
|
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. 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 notices of appeal with the
Supreme Court of Ohio alleging various errors made by the PUCO in its order
approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
and the Ohio Companies. The Appellees’ Merit Briefs were filed on
August 24, 2006 and the Appellants’ Reply Briefs were filed on
September 21, 2006. The OCC filed an amicus brief on August 4, 2006,
which the Ohio Companies moved to strike as improperly filed. The Supreme Court
denied the Ohio Companies’ motion on October 18, 2006.
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 recovered from January 1 through June 30, 2006
were approximately $61 million. That amount included the recovery of a
portion of the 2005 deferred MISO expenses as described below. On April 27,
2006, the Ohio Companies filed the annual update rider to determine revenues
($139 million) from July 2006 through June 2007. The filed rider went into
effect on July 1, 2006.
The
second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period 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. On
January 20,
2006, the OCC sought rehearing of the PUCO’s 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. 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
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 were heard on May 10, 2006. The Ohio Companies are
awaiting a final ruling from the Ohio Supreme Court, which is expected before
the end of 2006.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Ohio.
Pennsylvania
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 an agent for Met-Ed or Penelec in procuring the
services under 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. On September 26, 2006, Met-Ed and Penelec successfully
conducted a competitive RFP for 33% of their PLR obligation for which Committed
Resources have not been obtained for the period December 1, 2006 through
December 31, 2008.
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, further reduce, 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 CBP 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 of $37 million annually and an increase in distribution
rates for Penelec of $20 million annually. The PPUC suspended the effective
date (June 10, 2006) of these rate changes for seven months after the
filing as permitted under Pennsylvania law. If the PPUC adopts the overall
positions taken in the intervenors’ testimony as filed, this would have a
material adverse effect on the financial statements of FirstEnergy, Met-Ed
and
Penelec. Hearings were held in late August 2006 and all reply briefs were filed
by October 6, 2006. The ALJ’s recommended decision is due by November 8,
2006 and the PPUC decision is expected by January 12, 2007.
As
of
September 30, 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 were $297 million and
$56 million, respectively. Penelec's $56 million is subject to the
pending resolution of taxable income issues associated with NUG trust fund
proceeds. The PPUC recently conducted a review and audit of a modification
to
the NUG purchased power stranded cost accounting methodology for Met-Ed and
Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and
Penelec to reflect the deferred NUG cost balances as if the stranded cost
accounting methodology modification had not been implemented. As a result of
the
PPUC’s Order, Met-Ed recognized a pre-tax charge of approximately $10.3 million
in the third quarter of 2006, representing incremental costs deferred under
the
revised methodology in 2005. Met-Ed and Penelec continue to believe that the
stranded cost accounting methodology modification is appropriate and filed
a
petition with the PPUC pursuant to its Order for authorization to reflect the
stranded cost accounting methodology modification effective January 1, 1999.
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 all intervened in the case. 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 above. On May 4, 2006, the PPUC
approved the modified request. Accordingly, Met-Ed and Penelec have deferred
approximately $90 million and $21 million, respectively, representing
transmission costs that were incurred from January 1, 2006 through
September 30, 2006. On June 5, 2006, the OCA filed before the
Commonwealth Court a petition for review of the PPUC’s approval of the deferral.
On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the
OCA’s appeal. The ratemaking treatment of the deferrals will be determined in
the comprehensive rate filing proceeding discussed further above.
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 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 before the PPUC 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. On April 20, 2006, the PPUC approved the
Recommended Decision with additional modifications to use an RFP process with
two separate solicitations. An initial solicitation was held for Penn in May
2006 with all tranches fully subscribed, which was approved by the PPUC on
June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
Penn. The tranches for the Residential Group and Small Commercial Group were
fully subscribed. However, supply was not acquired for two tranches for the
Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
for
the second bid. A contingency solicitation was held on August 15, 2006 for
the two remaining Large Commercial Group tranches. The PPUC rejected the bids
from the contingency solicitation and directed Penn’s independent auction
manager to offer the two unfilled Large Commercial tranches to the companies
which had won tranches in the prior solicitations. This resulted in the
acquisition of a supplier for the two remaining tranches, which were filed
and
accepted by the PPUC in a secretarial letter that was entered on
September 22, 2006. On August 24, 2006, Penn made a compliance filing.
OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
exceptions on September 5, 2006. On September 21, 2006, Penn submitted
a revised compliance filing to the PPUC for the Residential Group and Small
Commercial Group as a result of an agreement between Penn, OCA and OSBA. The
PPUC approved proposed rates for the large commercial and industrial customers
at the PPUC Public meeting on October 19, 2006, and found that the results
of the competitive solicitation process were consistent with prevailing market
prices.
On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
April 28, 2006 and May 4, 2006, which together decided the issues
associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
impose a geographic limitation on the sources of alternative energy credits.
On
June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
ruling on the method by which alternative energy credits may be acquired and
traded. Penn is unable to predict the outcome of this appeal.
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 September 30, 2006, the
accumulated deferred cost balance totaled approximately $340 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
bonds associated with BGS stranded cost deferrals. On August 10, 2006,
JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued
$182 million of transition bonds with a weighted average interest rate of
5.5%.
On
December 2,
2005, JCP&L filed its 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 23, 2006, JCP&L filed updated data reflecting
actual amounts through December 31, 2005 of $154 million of costs
incurred since July 31, 2003. On March 29, 2006, a pre-hearing
conference was held with the presiding ALJ. On July 18, 2006, JCP&L
filed rebuttal testimony that included a request for an additional
$14 million of costs that had been eliminated from the securitized amount.
Evidentiary hearings were held during September 2006 and the briefing schedule
has been postponed pending settlement discussions.
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 latest quarterly reliability reports were submitted on
September 12, 2006. As of September 30, 2006, there were no
performance penalties issued by the NJBPU.
Reacting 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. On June 21, 2006,
the NJBPU approved the continued use of a descending block auction for the
Fixed
Price Residential Class. JCP&L filed its 2007 BGS company specific addendum
on July 10, 2006. On October 27, 2006, the NJBPU approved the auction
format to procure the 2007 Commercial Industrial Energy Price as well as the
specific rules for both the Fixed Price and Commercial Industrial Energy Price
auctions. These rules were essentially unchanged from the prior
auctions.
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 repeal
of
PUHCA pursuant to 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 on February 7, 2006 and comments were submitted
to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with
an effective date of October 2, 2006. These regulations are not expected to
materially impact FirstEnergy or JCP&L. Also in the same proceeding, the
NJBPU Staff issued an additional draft proposal on March 31, 2006
addressing various issues including access to books and records, ring-fencing,
cross subsidization, corporate governance and related matters. With the approval
of the NJBPU Staff, the affected utilities jointly submitted an alternative
proposal on June 1, 2006. Comments on the alternative proposal were submitted
on
June 15, 2006.
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 1, 2004,
ATSI filed with the FERC a request to defer approximately $54 million of costs
to be incurred from 2004 through 2007 in connection with ATSI’s 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 $34 million has been deferred as of
September 30, 2006). On March 28, 2006, ATSI and MISO filed with the 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 was June 1, 2006. Various
parties filed comments responsive to the March 28, 2006 submission. The FERC
conditionally approved the filing on May 22, 2006, subject to a compliance
filing that ATSI made on June 13, 2006. A request for rehearing of the FERC’s
May 22, 2006 Order was filed by a party, which ATSI answered. On July 14,
2006, the FERC accepted ATSI’s June 13, 2006 compliance filing. The estimated
annual revenues to ATSI from the VMEP cost recovery is $12 million for each
of
the five years beginning June 1, 2006. On October 25, 2006, the FERC
denied the request for rehearing.
On
January 24, 2006,
ATSI and MISO filed a request with the FERC 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 RTOR.
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,
the FERC approved the revenue credit correction without suspension, effective
April 1, 2006. One party sought rehearing of the FERC's order. The request
for
rehearing of this order was denied on June 27, 2006. The FERC accepted MISO’s
and ATSI’s revised tariff sheets for filing on June 7, 2006. The estimated
annual revenue impact of the correction mechanism is approximately $40 million
effective on June 1, 2006.
On
November 18,
2004, the FERC issued an order eliminating the RTOR for transmission service
between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
transmission owners within MISO and PJM to submit compliance filings containing
a SECA mechanism 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 was held in May 2006. Initial briefs were submitted
on
June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding Judge
issued an Initial Decision on August 10, 2006, rejecting the compliance filings
made by the RTOs and transmission owners, ruling on various issues and directing
new compliance filings. This decision is subject to review and approval by
the
FERC. Briefs addressing the Initial Decision were filed on September 11, 2006
and October 20, 2006. A final order could be issued by the FERC by the end
of
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 refund 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. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
the cost of all PJM transmission facilities should be recovered through a
postage stamp rate. The
ALJ recommended
an April 1, 2006 effective date for this change in rate design. If the FERC
accepts this recommendation, the transmission rate applicable to many load
zones
in PJM would increase. FirstEnergy believes that significant additional
transmission revenues would have to be recovered from the JCP&L, Met-Ed and
Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
on August 14, 2006 and September 5, 2006. The case will be reviewed by the
FERC
with a decision anticipated in the fourth quarter of 2006.
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 CBP 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.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio CBP, 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. Under the procedural
schedule approved in this case, FES expected an initial decision to be issued
in
late January 2007. However, on July 14, 2006, the Chief Judge granted the
joint
motion of FES and the Trial Staff to appoint a settlement judge in this
proceeding and the procedural schedule was suspended pending settlement
discussions among the parties. A settlement conference was held on September
5,
2006. FES and the Ohio Companies, Penn, and the PUCO, along
with other
parties, reached an agreement to settle the case. The settlement was filed
with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. Initial comments to the settlement are due
by
November 6, 2006.
The
terms of the
settlement provide for modification of both the Ohio and Penn power supply
agreements with FES. Under the Ohio power supply agreement, separate rates
are
established for the Ohio Companies’ PLR requirements, special retail contracts
requirements, wholesale contract requirements, and interruptible buy-through
retail load requirements. For their PLR and special retail contract
requirements, the Ohio Companies will pay FES no more than the lower of
(i) the
sum of the retail generation charge, the rate stabilization charge, the
fuel
recovery mechanism charge, and FES’ actual incremental fuel costs for such
sales; or (ii) the wholesale price cap. Different wholesale price caps
are
imposed for PLR sales, special retail contracts, and wholesale contracts.
The
wholesale price for interruptible buy-through retail load requirements
is
limited to the actual spot price of power obtained by FES to provide this
power.
The Ohio Companies have recognized the estimated additional amount payable
to
FES for power supplied during the nine months ended September 30, 2006.
The
wholesale rate charged by FES under the Penn power supply agreement will
be no
greater than the generation component of charges for retail PLR load in
Pennsylvania. The FERC is expected to act on this case by the end of the
fourth
quarter of 2006.
As
a result of
Penn’s PLR competitive solicitation process approved by the PPUC, FES was
selected as the winning bidder for a number of the tranches for individual
customer classes. The balance of the tranches will be supplied by unaffiliated
power suppliers. On October 2, 2006, FES filed an application with FERC under
Section 205 of the Federal Power Act for authorization to make these affiliate
sales to Penn. Interventions or protests were due on this filing on October
23,
2006. Penn was the only party to file an intervention in this proceeding.
The
FERC is expected to act on this filing on or before December 1,
2006.
On
October 19, 2006,
the FERC issued two final rules in connection with the Public Utility Holding
Company Act of 2005 (PUHCA 2005). The final rules impose certain accounting,
reporting and record-retention requirements for applicable holding companies
and
service companies, which includes FirstEnergy and certain of its
subsidiaries.
Environmental
Matters
FirstEnergy accrues environmental liabilities only 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 FirstEnergy’s
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.
Clean
Air Act
Compliance
FirstEnergy is required to meet federally-approved SO2
emissions
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
believes it is currently in compliance with this policy, but cannot predict
what
action the EPA may take in the future with respect to the interim enforcement
policy.
The EPA
Region
5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated
June
15, 2006 alleging violations to various sections of the Clean Air Act. A meeting
was held on August 8, 2006 to discuss the alleged violations with the EPA.
FirstEnergy has disputed those alleged violations based on its Clean Air Act
permit, the Ohio SIP and other information provided at the August 2006 meeting
with the EPA. The EPA has several enforcement options (administrative compliance
order, administrative penalty order, and/or judicial, civil or criminal action)
and has indicated that such option may depend on the time needed to achieve
and
demonstrate compliance with the rules alleged to have been
violated.
FirstEnergy complies 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 at
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 SIPs 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 fine
particulate matter. In March 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 facility 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 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. In
March 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 then,
new
and non-emitting generating facilities, including renewables and nuclear, would
be entitled to their proportionate share of the allowances. Consequently,
FirstEnergy will be disadvantaged if these model rules were implemented as
proposed because FirstEnergy’s substantial reliance on non-emitting (largely
nuclear) generation is not recognized under the input-based
allocation.
Pennsylvania has proposed a new rule to regulate mercury emissions from
coal-fired power plants that does not provide a cap and trade approach as in
CAMR, but rather follows a command and control approach imposing emission limits
on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation
would deprive FirstEnergy of mercury emission allowances that were to be
allocated to the Mansfield Plant under CAMR and that would otherwise be
available for achieving FirstEnergy system-wide compliance. The future cost
of
compliance with these regulations, if adopted and implemented as proposed,
may
be substantial.
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 ($400 million of which is expected to be spent in 2007 with the
primary portion of the remaining $1.1 billion expected to be spent in 2008
and
2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power
Corporation under which Bechtel will engineer, procure, and construct air
quality control systems for the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement with
B&W.
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 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.
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 September 30, 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
$73 million have been accrued through September 30, 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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
FirstEnergy companies also are defending six separate complaint cases before
the
PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of
their
insured. In each of these three 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 sixth case involves the claim of a non-customer seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003. That case has been dismissed. On
March 7,
2006, the PUCO issued a ruling, based on motions filed by the parties,
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 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.
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
that provide their service. The PUCO denied all other motions for rehearing.
The
plaintiffs in each case have since filed an amended complaint and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have been
set for hearing on October 16, 2007.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
County Common Pleas Court seeking reimbursement for claims paid to numerous
insureds who allegedly suffered losses as a result of the August 14, 2003
outage. All of the insureds appear to be non-customers. The plaintiff insurance
companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
the Ohio Companies and Penn were served on October 27, 2006, and expect to
seek summary dismissal of these cases based on the prior court rulings noted
above. No estimate of potential liability is available for any of these
cases.
FirstEnergy was also named, along with several other entities, in a complaint
in
New Jersey State Court. The allegations against FirstEnergy were based, in
part,
on an alleged failure to protect the citizens of Jersey City from an electrical
power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City.
A responsive pleading has been filed. On April 28, 2006, the Court granted
FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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 had 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
(not deductible for income tax purposes) which reduced FirstEnergy'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.
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 Nuclear Power 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 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
the
now repealed 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. On
October 18,
2006, the Ohio Supreme Court transferred this case to a Tuscarawas County Common
Pleas Court judge due to concerns over potential class membership by the
Jefferson County Common Pleas Court.
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 arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss as premature
a
JCP&L appeal of the award filed on October 18, 2005. JCP&L intends
to re-file an 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. Both filings were
consolidated for hearing and decision. 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.
On
May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
complaint and approving the related tariffs, thus affirming OE’s entitlement to
recovery of its transition charges.
The City of Huron
filed an application for rehearing of the PUCO’s decision on June 9, 2006
and OE filed a memorandum in opposition to that application on June 19,
2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
City of Huron has taken no further action and the period for filing an appeal
has expired.
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
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In
September 2006, the SEC issued SAB 108, which provides interpretive guidance
on
how registrants should quantify financial statement misstatements. There is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments will
need to be reconsidered using both the rollover and iron curtain methods. This
guidance will be effective for FirstEnergy in the fourth quarter of 2006.
FirstEnergy does
not expect this
Statement to have a material impact on its financial statements.
|
EITF
06-5
- “Accounting for Purchases of Life Insurance-Determining the Amount
That
Could Be Realized in Accordance with FASB Technical Bulletin No.
85-4,
Accounting for Purchases of Life
Insurance”
|
In September 2006, the EITF reached a consensus on Issue 06-5 concluding that
a
policyholder should consider any additional amounts included in the contractual
terms of the policy in determining the amount that could be realized under
the
insurance contract. Contractual limitations should be considered when
determining the realizable amounts. Amounts that are recoverable by the
policyholder at the discretion of the insurance company should be excluded
from
the amount that could be realized. Recoverable amounts in periods beyond one
year from the surrender of the policy should be discounted in accordance with
APB Opinion No. 21, “Interest on Receivables and Payables.” Consensus was
also reached that a policyholder should determine the amount that could be
realized under the insurance contract assuming the surrender of an
individual-life by individual-life policy (or certificate by certificate in
a
group policy). Any amount that would ultimately be realized by the policyholder
upon the assumed surrender of the final policy (or final certificate) should
be
included in the amount that could be realized under the insurance contract.
The
EITF also concluded that a policyholder should not discount the cash surrender
value component of the amount that could be realized when contractual
restrictions on the ability to surrender a policy exist. However, if the
contractual limitations prescribe that the cash surrender value component of
the
amount that could be realized is a fixed amount, then the amount that could
be
realized should be discounted in accordance with APB Opinion No. 21. This
Issue is effective for fiscal years beginning after December 15, 2006.
FirstEnergy does not expect this EITF to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
FirstEnergy is currently evaluating the impact of this Statement on its
financial statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for FirstEnergy as of December 31, 2006. Based upon
the December 31, 2005 measurement date, the estimated balance sheet impacts
of adopting this Statement are a reduction in total assets of $0.4 billion,
an increase in liabilities of $0.6 billion and a decrease in equity of
$1 billion, before recognition of any related regulatory assets that may be
appropriate under the circumstances.
FSP
FIN 46(R)-6
- “Determining the Variability to Be Considered in Applying FASB interpretation
No. 46(R)”
In
April 2006, the
FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
determine the variability to be considered in applying FASB interpretation
No.
46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter
of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
determined to be the VIE’s primary beneficiary. The variability that is
considered in applying interpretation 46(R) affects the determination of (a)
whether the entity is a VIE; (b) which interests are variable interests in
the
entity; and (c) which party, if any, is the primary beneficiary of the VIE.
This
FSP states that the variability to be considered shall be based on an analysis
of the design of the entity, involving two steps:
Step
1:
|
Analyze
the
nature of the risks in the entity
|
Step
2:
|
Determine
the
purpose(s) for which the entity was created and determine the variability
the entity is designed to create and pass along to its interest
holders.
|
After
determining
the variability to consider, the reporting enterprise can determine which
interests are designed to absorb that variability. The guidance in this FSP
is
applied prospectively to all entities (including newly created entities) with
which that enterprise first becomes involved and to all entities previously
required to be analyzed under interpretation 46(R) when a reconsideration event
has occurred after July 1, 2006. FirstEnergy does not expect this Statement
to have a material impact on its financial statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. FirstEnergy
is
currently evaluating the impact of this Statement.
OHIO
EDISON
COMPANY
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE
INCOME
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
673,673
|
|
$
|
825,790
|
|
$
|
1,832,968
|
|
$
|
2,268,760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,954
|
|
|
15,158
|
|
|
8,726
|
|
|
39,080
|
|
Purchased
power
|
|
|
395,560
|
|
|
229,561
|
|
|
971,613
|
|
|
703,658
|
|
Nuclear
operating costs
|
|
|
44,995
|
|
|
76,254
|
|
|
129,585
|
|
|
264,514
|
|
Other
operating costs
|
|
|
108,362
|
|
|
114,762
|
|
|
290,776
|
|
|
293,530
|
|
Provision
for
depreciation
|
|
|
18,399
|
|
|
30,169
|
|
|
53,962
|
|
|
87,875
|
|
Amortization
of regulatory assets
|
|
|
49,717
|
|
|
126,439
|
|
|
147,022
|
|
|
347,880
|
|
Deferral
of
new regulatory assets
|
|
|
(44,962
|
)
|
|
(43,929
|
)
|
|
(123,285
|
)
|
|
(107,750
|
)
|
General
taxes
|
|
|
47,826
|
|
|
51,945
|
|
|
137,652
|
|
|
146,066
|
|
Total
expenses
|
|
|
622,851
|
|
|
600,359
|
|
|
1,616,051
|
|
|
1,774,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
50,822
|
|
|
225,431
|
|
|
216,917
|
|
|
493,907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
32,993
|
|
|
25,260
|
|
|
98,853
|
|
|
68,349
|
|
Miscellaneous
income (expense)
|
|
|
1,639
|
|
|
368
|
|
|
835
|
|
|
(23,529
|
)
|
Interest
expense
|
|
|
(24,597
|
)
|
|
(17,182
|
)
|
|
(60,195
|
)
|
|
(56,787
|
)
|
Capitalized
interest
|
|
|
698
|
|
|
3,014
|
|
|
1,832
|
|
|
8,255
|
|
Subsidiary's
preferred stock dividend requirements
|
|
|
(156
|
)
|
|
(156
|
)
|
|
(467
|
)
|
|
(1,534
|
)
|
Total
other
income (expense)
|
|
|
10,577
|
|
|
11,304
|
|
|
40,858
|
|
|
(5,246
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
61,399
|
|
|
236,735
|
|
|
257,775
|
|
|
488,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
17,902
|
|
|
105,337
|
|
|
91,239
|
|
|
253,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
43,497
|
|
|
131,398
|
|
|
166,536
|
|
|
235,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AND
REDEMPTION PREMIUM
|
|
|
51
|
|
|
659
|
|
|
4,297
|
|
|
1,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
43,446
|
|
$
|
130,739
|
|
$
|
162,239
|
|
$
|
233,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
43,497
|
|
$
|
131,398
|
|
$
|
166,536
|
|
$
|
235,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
3,795
|
|
|
(3,402
|
)
|
|
5,467
|
|
|
(19,079
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
1,369
|
|
|
(2,043
|
)
|
|
1,972
|
|
|
(7,713
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
2,426
|
|
|
(1,359
|
)
|
|
3,495
|
|
|
(11,366
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
45,923
|
|
$
|
130,039
|
|
$
|
170,031
|
|
$
|
223,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
703
|
|
|
$
|
929
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $15,017,000 and $7,619,000,
respectively,
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
255,173
|
|
|
|
290,887
|
|
Associated
companies
|
|
|
190,516
|
|
|
|
187,072
|
|
Other
(less
accumulated provisions of $1,058,000 and $4,000,
respectively,
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
21,399
|
|
|
|
15,327
|
|
Notes
receivable from associated companies
|
|
|
471,393
|
|
|
|
536,629
|
|
Prepayments
and other
|
|
|
19,053
|
|
|
|
93,129
|
|
|
|
|
958,237
|
|
|
|
1,123,973
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,599,266
|
|
|
|
2,526,851
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,005,404
|
|
|
|
984,463
|
|
|
|
|
1,593,862
|
|
|
|
1,542,388
|
|
Construction
work in progress
|
|
|
48,397
|
|
|
|
58,785
|
|
|
|
|
1,642,259
|
|
|
|
1,601,173
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
1,675,813
|
|
|
|
1,758,776
|
|
Investment
in
lease obligation bonds
|
|
|
310,077
|
|
|
|
325,729
|
|
Nuclear
plant
decommissioning trusts
|
|
|
111,325
|
|
|
|
103,854
|
|
Other
|
|
|
39,734
|
|
|
|
44,210
|
|
|
|
|
2,136,949
|
|
|
|
2,232,569
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
746,001
|
|
|
|
774,983
|
|
Prepaid
pension costs
|
|
|
229,316
|
|
|
|
224,813
|
|
Property
taxes
|
|
|
52,897
|
|
|
|
52,875
|
|
Unamortized
sale and leaseback costs
|
|
|
51,386
|
|
|
|
55,139
|
|
Other
|
|
|
27,463
|
|
|
|
31,752
|
|
|
|
|
1,107,063
|
|
|
|
1,139,562
|
|
|
|
$
|
5,844,508
|
|
|
$
|
6,097,277
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
226,191
|
|
|
$
|
280,255
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
1,608
|
|
|
|
57,715
|
|
Other
|
|
|
22,097
|
|
|
|
143,585
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
146,370
|
|
|
|
172,511
|
|
Other
|
|
|
10,811
|
|
|
|
9,607
|
|
Accrued
taxes
|
|
|
136,044
|
|
|
|
163,870
|
|
Accrued
interest
|
|
|
21,172
|
|
|
|
8,333
|
|
Other
|
|
|
100,742
|
|
|
|
61,726
|
|
|
|
|
665,035
|
|
|
|
897,602
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares -
|
|
|
1,796,560
|
|
|
|
2,297,253
|
|
80
and 100
shares outstanding, respectively
|
|
|
|
|
|
|
|
|
Accumulated
other comprehensive income
|
|
|
7,589
|
|
|
|
4,094
|
|
Retained
earnings
|
|
|
290,880
|
|
|
|
200,844
|
|
Total
common
stockholder's equity
|
|
|
2,095,029
|
|
|
|
2,502,191
|
|
Preferred
stock not subject to mandatory redemption
|
|
|
-
|
|
|
|
60,965
|
|
Preferred
stock of consolidated subsidiary not subject to mandatory
redemption
|
|
|
14,105
|
|
|
|
14,105
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,526,833
|
|
|
|
1,019,642
|
|
|
|
|
3,635,967
|
|
|
|
3,596,903
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
736,396
|
|
|
|
769,031
|
|
Accumulated
deferred investment tax credits
|
|
|
21,419
|
|
|
|
24,081
|
|
Asset
retirement obligations
|
|
|
86,893
|
|
|
|
82,527
|
|
Retirement
benefits
|
|
|
296,634
|
|
|
|
291,051
|
|
Deferred
revenues - electric service programs
|
|
|
96,718
|
|
|
|
121,693
|
|
Other
|
|
|
305,446
|
|
|
|
314,389
|
|
|
|
|
1,543,506
|
|
|
|
1,602,772
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$
|
5,844,508
|
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
166,536
|
|
$
|
235,251
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
53,962
|
|
|
87,875
|
|
Amortization
of regulatory assets
|
|
|
147,022
|
|
|
347,880
|
|
Deferral
of
new regulatory assets
|
|
|
(123,285
|
)
|
|
(107,750
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
728
|
|
|
30,530
|
|
Amortization
of lease costs
|
|
|
28,600
|
|
|
30,011
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(27,850
|
)
|
|
(22,929
|
)
|
Accrued
compensation and retirement benefits
|
|
|
2,985
|
|
|
10,261
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
26,198
|
|
|
110,460
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(2,538
|
)
|
Prepayments
and other current assets
|
|
|
(4,172
|
)
|
|
(4,232
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(24,937
|
)
|
|
(105,234
|
)
|
Accrued
taxes
|
|
|
(27,826
|
)
|
|
60,443
|
|
Accrued
interest
|
|
|
12,839
|
|
|
1,667
|
|
Electric
service prepayment programs
|
|
|
(24,975
|
)
|
|
127,586
|
|
Other
|
|
|
1,842
|
|
|
1,372
|
|
Net
cash
provided from operating activities
|
|
|
207,667
|
|
|
800,653
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
592,763
|
|
|
146,450
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
65,696
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(500,000
|
)
|
|
-
|
|
Preferred
stock
|
|
|
(63,893
|
)
|
|
(37,750
|
)
|
Long-term
debt
|
|
|
(138,085
|
)
|
|
(278,327
|
)
|
Short-term
borrowings, net
|
|
|
(177,595
|
)
|
|
-
|
|
Dividend
Payments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(73,000
|
)
|
|
(241,000
|
)
|
Preferred
stock
|
|
|
(1,369
|
)
|
|
(1,976
|
)
|
Net
cash used
for financing activities
|
|
|
(361,179
|
)
|
|
(346,907
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(94,278
|
)
|
|
(190,804
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
34,655
|
|
|
196,235
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(36,038
|
)
|
|
(219,890
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
148,199
|
|
|
(258,561
|
)
|
Cash
investments
|
|
|
93,900
|
|
|
13,372
|
|
Other
|
|
|
6,848
|
|
|
5,572
|
|
Net
cash
provided from (used for) investing activities
|
|
|
153,286
|
|
|
(454,076
|
)
|
|
|
|
|
|
|
|
|
Net
decrease
in cash and cash equivalents
|
|
|
(226
|
)
|
|
(330
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
929
|
|
|
1,230
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
703
|
|
$
|
900
|
|
|
|
|
|
|
|
|
|
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 September 30, 2006, and the related consolidated statements
of income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2006 and 2005 and the consolidated statements of
cash flows for the nine-month periods ended September 30, 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.
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
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. Penn’s rate restructuring plan and its
associated transition charge revenue recovery was completed in 2005. 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
In 2005, the Ohio Companies and Penn 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 affect the OE Companies' comparative earnings 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 Plant and Beaver Valley 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
continues to provide OE’s PLR requirements under revised purchased power
arrangements covering the three-year period beginning January 1, 2006 and
Penn’s during the remainder of 2006 (see Outlook -
Regulatory
Matters).
The effects on the OE Companies' results of operations in the third quarter
and
nine months ended September 30, 2006 as compared to the same periods 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
|
Income
Statement Effects
|
|
Three
Months
|
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(44)
|
|
|
$
|
(133)
|
|
Nuclear-generated
KWH sales
|
(b)
|
|
(86)
|
|
|
|
(217)
|
|
Total
-
Revenues Effect
|
|
|
(130)
|
|
|
|
(350)
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(12)
|
|
|
|
(30)
|
|
Nuclear
operating costs
|
(c)
|
|
(33)
|
|
|
|
(122)
|
|
Provision
for
depreciation
|
(d)
|
|
(15)
|
|
|
|
(43)
|
|
General
taxes
|
(e)
|
|
(3)
|
|
|
|
(9)
|
|
Total
-
Expenses Effect
|
|
|
(63)
|
|
|
|
(204)
|
|
Operating
Income Effect
|
|
|
(67)
|
|
|
|
(146)
|
|
Other
Income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
14
|
|
|
|
44
|
|
Nuclear
decommissioning trust earnings
|
(g)
|
|
(5)
|
|
|
|
(11)
|
|
Capitalized
Interest
|
(h)
|
|
(3)
|
|
|
|
(7)
|
|
Total
- Other
Income Effect
|
|
|
6
|
|
|
|
26
|
|
Income
taxes
|
(i)
|
|
(25)
|
|
|
|
(49)
|
|
Net
Income
Effect
|
|
$
|
(36)
|
|
|
$
|
(71)
|
|
|
|
|
|
|
|
|
|
|
(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.
|
Results
of Operations
Earnings
on common
stock in the third quarter of 2006 decreased to $43 million from $131
million in the third quarter of 2005. In the first nine months of 2006, earnings
on common stock decreased to $162 million from $233 million in the same
period of 2005. The change in earnings in both periods reflected the effects
of
the generation asset transfer shown in the table above. Expenses during the
third quarter of 2006 included $25 million of costs associated with the
proposed FERC settlement (see Note 11) applicable to the first half of 2006.
Earnings in the first nine months of 2005 were reduced by additional income
taxes of $36 million from the implementation of Ohio tax legislation changes
and
charges related to an $8.5 million civil penalty payable to the DOJ and
$10 million for environmental projects in connection with the Sammis Plant
settlement (see Outlook — Environmental Matters).
Revenues
Revenues
decreased
by $152 million or 18.4% in the third 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, revenues in
the
third quarter of 2006 decreased $22 million, primarily due to decreases of
$68
million and $127 million in wholesale sales and distribution revenues,
respectively, partially offset by increases in retail generation revenues of
$149 million and reduced customer shopping incentives of $24 million.
In
the first nine
months of 2006 compared with the same period in 2005, revenues decreased by
$436
million or 19.2%, primarily from the generation asset transfer impact summarized
in the table above. Excluding the effects of the asset transfer, revenues in
the
first nine months of 2006 decreased $86 million, primarily due to decreases
of
$198 million and $337 million in wholesale sales and distribution revenues,
respectively, partially offset by increases in retail generation revenues of
$381 million and reduced customer shopping incentives of $62
million.
The
lower wholesale
revenues in both periods of 2006 primarily resulted from the termination of
a
non-affiliated wholesale sales agreement and the December 2005 cessation of
the
MSG sales arrangements under OE’s transition plan. OE had been required to
provide the MSG to non-affiliated alternative suppliers.
Changes
in electric
generation KWH sales and revenues
in the
third quarter and first nine months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Generation KWH Sales
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
14.9
|
%
|
|
13.3
|
%
|
Wholesale
|
|
|
(85.8)
|
%
|
|
(83.9)
|
%
|
Net
Decrease in Generation Sales
|
|
|
(32.7)
|
%
|
|
(30.7)
|
%
|
Changes
in Generation Revenues
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Retail
Generation:
|
|
|
|
|
|
|
|
Residential
|
|
$
|
59
|
|
$
|
143
|
|
Commercial
|
|
|
46
|
|
|
116
|
|
Industrial
|
|
|
44
|
|
|
122
|
|
Total
Retail
Generation
|
|
|
149
|
|
|
381
|
|
Wholesale*
|
|
|
(68
|
)
|
|
(198
|
) |
Net
Increase in Generation Revenues
|
|
$
|
81
|
|
$
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Excludes
impact of generation asset transfers related to nuclear-generated
KWH
sales.
|
Increased
retail
generation revenues for the third quarter of 2006 (as shown in the table above)
resulted from 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: residential - 12.4 percentage
points; commercial - 13.0 percentage points; and industrial - 10.9 percentage
points. The decrease in shopping resulted from certain alternative energy
suppliers terminating their supply arrangements with OE’s shopping customers in
the fourth quarter of 2005. Higher unit prices for generation reflected the
rate
stabilization charge and the fuel recovery rider that both became effective
in
the first quarter of 2006 under provisions of the RSP and RCP.
Retail
generation
revenues increased in the first nine months of 2006 compared to the same period
of 2005 for the reasons described above. The increase in generation KWH sales
primarily resulted from a decrease in customer shopping, as the percentage
of
generation services provided by alternative suppliers to total sales delivered
in OE's service area decreased by: residential - 10.6 percentage points;
commercial - 12.2 percentage points; and industrial - 10.5 percentage points.
Higher unit prices for generation reflected the impact of the RSP and RCP
described above.
Changes
in
distribution KWH deliveries and
revenues in the
third quarter and first nine months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(4.2)
|
%
|
|
(3.9)
|
%
|
Commercial
|
|
|
(1.4)
|
%
|
|
(1.5)
|
%
|
Industrial
|
|
|
0.3
|
%
|
|
0.4
|
%
|
Net
Decrease in Distribution Deliveries
|
|
|
(1.8)
|
%
|
|
(1.7)
|
%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Nine
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Residential
|
|
$
|
(60)
|
|
$
|
(148)
|
|
Commercial
|
|
|
(37)
|
|
|
(102)
|
|
Industrial
|
|
|
(30)
|
|
|
(87)
|
|
Net
Decrease in Distribution Revenues
|
|
|
(127)
|
|
$
|
(337)
|
|
Lower
distribution
revenues shown in the table above for the third quarter and first nine months
of
2006 reflect lower composite prices and reduced KWH deliveries to residential
and commercial customers. The lower unit prices in both periods resulted from
the completion of the generation-related transition cost recovery under the
OE
Companies’ respective rate restructuring plans
in 2005,
partially offset by increased transmission rates to recover MISO costs beginning
in 2006 (see Outlook - Regulatory Matters). Lower KWH deliveries to residential
and commercial customers reflected the impact of milder weather conditions
in
the third quarter and first nine months of 2006, compared to the same periods
of
2005. KWH deliveries to industrial customers increased slightly in both periods
due to the recovering steel industry in the OE Companies’ service
territory.
Under
the Ohio
transition plan, OE provided incentives to customers to encourage switching
to
alternative energy providers, which reduced OE’s revenues by $24 million in the
third quarter of 2005 and $62 million in the first nine months of 2005. These
revenue reductions, which were deferred for future recovery and did not affect
earnings, ceased in 2006. The deferred shopping incentives (Extended RTC) are
now being recovered under the RCP (see Outlook - Regulatory
Matters).
Expenses
Total
expenses
increased by $22 million in the third quarter of 2006 and decreased by
$159 million in the first nine months of 2006 from the same periods of
2005. The change in both periods was impacted by the effects of the
generation asset transfers shown in the table above. Excluding the asset
transfer effects, the following table presents changes from the prior year
by
expense category:
Expenses
- Changes
|
|
Three
Months
|
|
Nine
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Purchased
power costs
|
|
$
|
166
|
|
$
|
268
|
|
Nuclear
operating costs
|
|
|
2
|
|
|
(12
|
) |
Other
operating costs
|
|
|
(7
|
) |
|
(3
|
) |
Provision
for
depreciation
|
|
|
3
|
|
|
9
|
|
Amortization
of regulatory assets
|
|
|
(77
|
) |
|
(201
|
) |
Deferral
of
new regulatory assets
|
|
|
(1
|
) |
|
(16
|
) |
General
taxes
|
|
|
(2
|
) |
|
-
|
|
Net
increase in expenses
|
|
$
|
84
|
|
|
45
|
|
|
|
|
|
|
|
|
|
Increased
purchased
power costs in the third quarter and first nine months 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. Excluding the effects of the generation asset transfers, the
lower
nuclear operating costs in the first nine months of 2006 for OE’s nuclear
leasehold interests were primarily due to the absence in 2006 of both the Beaver
Valley Unit 2 refueling outage in 2005 and the Perry Nuclear Power Plant
scheduled refueling outage (including an unplanned extension) that was completed
on May 6, 2005. The decrease in other operating costs during the third quarter
and the first nine months of 2006 was primarily due to lower associated company
(FES) transmission expenses as a result of alternative energy suppliers
terminating their supply arrangements with OE’s shopping customers in the fourth
quarter of 2005 and lower employee benefit expenses. These decreases in the
first nine months of 2006 were partially offset by increases in 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
third quarter and first nine months of 2006 reflected capital additions
subsequent to the third quarter of 2005. Lower amortization of regulatory assets
in both periods was due to the completion of the generation-related transition
cost amortization under the OE Companies' respective transition plans, partially
offset by the amortization of deferred MISO costs being recovered in 2006.
The
higher deferrals of new regulatory assets in the third quarter and first nine
months of 2006 primarily resulted from the deferral of fuel costs ($21 million
and $45 million, respectively) and distribution costs ($18 million and $58
million, respectively) under the RCP, partially offset by lower MISO cost
deferrals ($13 million and $23 million, respectively) and the decrease in
shopping incentive deferrals ($25 million and $64 million, respectively) which
ceased in 2006 under the Ohio transition plan. The deferral of interest on
the
unamortized shopping incentive balances continues under the RCP.
Other
Income
(Expense)
Other
income
decreased $1 million in the third quarter of 2006 as compared with the same
period of 2005, reflecting the effects of the generation asset transfers.
Excluding the effects of the generation asset transfers, the $8 million decrease
in the third quarter of 2006 was primarily due to an additional $10 million
of
interest expense from OE’s June 2006 issuance of $600 million of long-term debt.
As discussed below under Capital Resources and Liquidity, OE primarily used
the
debt proceeds to repurchase $500 million of its common stock from FirstEnergy.
This represents a part of FirstEnergy’s 2006 refinancing strategy to obtain
additional holding company financing flexibility by using the OE common stock
repurchase proceeds to redeem holding company debt and to capitalize its
regulated utility subsidiaries more appropriately from a regulatory context.
Other
income
increased $46 million in the first nine months of 2006 as compared with the
same
period of 2005, primarily due to the effects of the generation asset transfers.
Excluding the effects of the generation asset transfers, the $20 million
increase in the first nine months of 2006 is primarily due to the absence in
2006 of the 2005 charges of $8.5 million for a 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) partially offset by a $3 million increase in interest expense. The
interest expense increase reflected the effect of the June 2006 long-term debt
issuance discussed above, and was partially offset by the impact of other debt
redemptions subsequent to the third quarter of 2005.
Income
Taxes
Income
taxes
decreased $87 million in the third quarter of 2006 and $162 million
in the first nine months of 2006 compared with the same periods of 2005.
Excluding the effects of the generation asset transfer, income taxes decreased
$63 million in the third quarter of 2006 and $113 million
in
the first nine months of 2006. The
decreases in
both periods was mainly due to decreases in taxable income, partially offset
by
a reduction in the tax rates due to the continuing phase-out of the income-based
Ohio franchise tax. The income taxes
decrease in the
first nine months of 2006 also reflected the absence in 2006 of a $36
million
write-off of net deferred tax benefits in the second quarter of 2005, resulting
from the new Ohio tax legislation in 2005.
Capital
Resources and Liquidity
OE’s
cash
requirements for the remainder of 2006 for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met with cash
from
operations and short-term credit arrangements. OE repurchased $500 million
of
common stock from FirstEnergy and redeemed $64 million of preferred stock
(including redemption premiums) in July 2006 with proceeds of senior notes
issued in June 2006. Available borrowing capacity under credit facilities will
be used to manage working capital requirements.
Changes
in Cash
Position
OE
had $703,000 of
cash and cash equivalents as of September 30, 2006 compared with $929,000 as
of
December 31, 2005. The major sources for changes in these balances are
summarized below.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities during the first nine months of 2006, compared with the
corresponding period in 2005, was as follows:
|
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
Operating
Cash Flows
|
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
millions)
|
|
Cash
earnings
(1)
|
|
|
$
|
224
|
|
$
|
603
|
|
Working
capital and other
|
|
|
|
(16
|
) |
|
198
|
|
Net
cash
provided from operating activities
|
|
|
$
|
208
|
|
$
|
801
|
|
|
|
|
|
|
|
|
|
|
(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 is a useful financial measure because
it
provides investors and management with an additional means of evaluating its
cash-based operating performance. Generally,
a
non-GAAP financial measure is a numerical measure of a company’s historical or
future financial performance, financial position, or cash flows that either
excludes or includes amounts, or is subject to adjustment that has the effect
of
excluding or including amounts, that are not normally excluded or included
in
the most directly comparable measure calculated and presented in accordance
with
GAAP. In addition, cash earnings (non-GAAP) are not defined under GAAP.
Management believes presenting this non-GAAP measure provides useful information
to investors in assessing OE’s operating performance from a cash perspective
without the effects of material unusual economic events. OE’s management
frequently references these non-GAAP financial measures in its decision-making,
using them to facilitate historical and ongoing performance comparisons as
well
as comparisons to the performance of peer companies. These non-GAAP measures
should be considered in addition to, and not as a substitute for, their most
directly comparable financial measures prepared in accordance with
GAAP.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
167
|
|
$
|
235
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
54
|
|
|
88
|
|
Amortization
of regulatory assets
|
|
|
147
|
|
|
348
|
|
Deferral
of
new regulatory assets
|
|
|
(123)
|
|
|
(108)
|
|
Nuclear
fuel
and capital lease amortization
|
|
|
1
|
|
|
31
|
|
Amortization
of electric service obligation
|
|
|
(25)
|
|
|
(8)
|
|
Amortization
of lease costs
|
|
|
28
|
|
|
30
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(28)
|
|
|
(23)
|
|
Accrued
compensation and retirement benefits
|
|
|
3
|
|
|
10
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
224
|
|
$
|
603
|
|
|
|
|
|
|
|
|
|
Net
cash provided
from operating activities decreased $593 million in the first nine months
of 2006, compared with the same period in 2005, due to a $379 million
decrease in cash earnings as described above under “Results of Operations” and a
$214 million decrease from changes in working capital. The decrease in working
capital primarily reflects the absence in 2006 of $136 million in funds received
under the Energy for Education program in 2005 and changes in accrued taxes
of
$88 million and accounts receivable of $84 million, partially offset by
changes in accounts payable of $80 million.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities increased by $14 million in the first nine months of
2006 from the same period last year. The increase in funds used for financing
activities primarily resulted from a $500 million repurchase of common stock,
partially offset by a $317 million decrease in net preferred stock and debt
redemptions and a $168 million decrease in common stock dividend payments to
FirstEnergy.
OE
had approximately
$472 million of cash and temporary cash investments (which include short-term
notes receivable from associated companies) and $24 million of short-term
indebtedness as of September 30, 2006. OE has authorization from the PUCO to
incur short-term debt of up to $500 million, which is available through the
bank facility and the utility money pool described below. Penn has authorization
from the FERC to incur short-term debt up to its charter limit of
$44 million as of September 30, 2006, and also has 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 September 30, 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 $25 million under a receivables
financing arrangement which expires July 28,
2007.
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 September 30,
2006, the facility was drawn for $19 million.
As
of September 30,
2006, OE and Penn had the aggregate capability to issue approximately
$592 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 $655 million as of September 30, 2006. Based upon applicable earnings
coverage tests in its charter, Penn could issue a total of $136 million of
preferred stock (assuming no additional debt was issued) as of
September 30, 2006. As
a result of OE
redeeming all of its outstanding preferred stock on July 7, 2006, the applicable
earnings coverage test is inoperable for OE. In the event that OE issues
preferred stock in the future, the applicable earnings coverage test will govern
the amount of additional preferred stock that OE may issue.
As
of September 30,
2006, OE had approximately $400 million of capacity remaining unused under
its existing shelf registration for unsecured debt securities.
On
August 24,
2006, FirstEnergy,
OE,
Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered
into a new $2.75 billion five-year revolving credit facility which replaced
the
prior $2 billion credit facility. FirstEnergy may request an increase in the
total commitments available under the new facility up to a maximum of $3.25
billion. Commitments under the new facility are available until August 24,
2011, unless the lenders agree, at the request of the Borrowers, to two
additional one-year extensions. Generally, borrowings under the facility must
be
repaid within 364 days. Available amounts for each Borrower are subject to
a
specified sub-limit, as well as applicable regulatory and other limitations.
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 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 the credit facility and accounts receivable financing facilities totaled
$726 million as of September 30, 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 September 30,
2006, debt to total capitalization as defined under the revolving credit
facility was 46% for OE and 33% for Penn.
The
revolving credit
facility does not contain any provisions that either restricts 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 nine months of 2006 was 5.09%.
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.
On April 3, 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 FGCO’s and NGC’s
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.
On
June 26,
2006, OE issued $600 million of unsecured senior notes, comprised of $250
million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The
net proceeds from this offering were used in July 2006 to repurchase $500
million of OE common stock from FirstEnergy, redeem approximately $61 million
of
its preferred stock and to reduce short-term borrowings.
Cash
Flows From
Investing Activities
Net
cash provided
from investing activities was $153 million in the first nine months of 2006
compared to $454 million used for investing activities in the first nine months
of 2005. The change resulted primarily from a $407 million increase in loan
repayments from associated companies and a $97 million decrease in property
additions, which reflects the impact of the generation asset transfers and
$78 million from liquidating investments (restrictions on short-term
investments expired for an escrow fund and a mortgage indenture deposit).
In
the last quarter
of 2006, capital requirements for property additions and capital leases are
expected to be approximately $20 million. OE has additional requirements of
approximately $2 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 and short-term credit arrangements. OE’s
capital
spending for the period 2006-2010 is expected to be approximately $630 million,
of which approximately $114 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 $655 million as of September 30, 2006.
Equity
Price Risk
Included
in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $73 million and $67 million
as of
September 30, 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 September 30, 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
and liabilities are costs which have been authorized by the PUCO, the PPUC
and
the FERC for recovery from, or credit to, customers in future periods or for
which authorization is probable. Without the probability of such authorization,
costs currently recorded as regulatory assets and liabilities would have been
charged or creditied to income as incurred. All regulatory assets are expected
to be recovered under the provisions of OE’s transition plan. OE‘s regulatory
assets were $746 million and $775 million as of September 30,
2006 and December 31, 2005, respectively. Penn had net regulatory liabilities
of
$64 million and $59 million as of September 30, 2006 and December 31, 2005,
respectively, which are included in Other Noncurrent Liabilities on the
Consolidated Balance Sheets as of September 30, 2006 and December 31,
2005.
On
October 21, 2003,
the Ohio Companies filed their 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
the
PUCO’s 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 the proceeding as well as the associated entries
on
rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
the PUCO's order with respect to the approval of the rate stabilization charge,
approval of the shopping credits, the granting of interest on shopping credit
incentive deferral amounts, and approval of the Ohio Companies’ financial
separation plan. It remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the competitive
marketplace. The RSP contained a provision that permitted the Ohio Companies
to
withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
have
30 days from the final order or decision to provide notice of termination.
On
July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
a
Proceeding on Remand. In their Request, the Ohio Companies provided notice
of
termination to those provisions of the RSP subject to termination, subject
to
being withdrawn, and also set forth a framework for addressing the Supreme
Court
of Ohio’s findings on customer participation, requesting the PUCO to initiate a
proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
resolution to the issues raised by the Supreme Court of Ohio that is acceptable
to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
considered to be null and void. Separately, the OCC and NOAC also submitted
to
the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
by
the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
to
address the Court’s concern. On September 19, 2006, the PUCO issued an
Entry granting the Ohio Companies’ motion for extension of time to file the
remand proposal. The Ohio Companies filed their RSP Remand CBP on
September 29, 2006. No further proceedings have been scheduled at this
time.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
November 4, 2005, the Ohio Companies filed a supplemental stipulation with
the
PUCO, which constituted an additional component of the RCP filed on September
9,
2005. 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 balances 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.
|
The following table provides OE’s estimated net 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
|
|
$
|
173
|
|
2007
|
|
|
180
|
|
2008
|
|
|
207
|
|
Total
Amortization
|
|
$
|
560
|
|
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. 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 notices of appeal with the
Supreme Court of Ohio alleging various errors made by the PUCO in its order
approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
and the Ohio Companies. The Appellees’ Merit Briefs were filed on
August 24, 2006 and the Appellants’ Reply Briefs were filed on
September 21, 2006. The OCC filed an amicus brief on August 4, 2006,
which the Ohio Companies moved to strike as improperly filed. The Supreme Court
denied the Ohio Companies’ motion on October 18, 2006.
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 recovered
from
January 1 through June 30, 2006 were approximately
$31
million. That
amount included the
recovery of a portion of the 2005 deferred MISO expenses as described below.
On
April 27, 2006, OE filed the annual update rider to determine revenues
($70 million) from July
2006 through June
2007. The filed rider went into effect on July 1,
2006.
The
second
application sought authority to defer costs associated with transmission and
ancillary service related costs incurred during the period 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. On
January 20,
2006, the OCC sought rehearing of the PUCO’s 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. 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
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 were heard on May 10, 2006. The Ohio Companies are
awaiting a final ruling from the Ohio Supreme Court, which is expected before
the end of 2006.
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 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 before the PPUC 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. On April 20, 2006, the PPUC approved the
Recommended Decision with additional modifications to use an RFP process with
two separate solicitations. An initial solicitation was held for Penn in May
2006 with all tranches fully subscribed, which was approved by the PPUC on
June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
Penn. The tranches for the Residential Group and Small Commercial Group were
fully subscribed. However, supply was not acquired for two tranches for the
Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
for
the second bid. A contingency solicitation was held on August 15, 2006 for
the two remaining Large Commercial Group tranches. The PPUC rejected the bids
from the contingency solicitation and directed Penn’s independent auction
manager to offer the two unfilled Large Commercial tranches to the companies
which had won tranches in the prior solicitations. This resulted in the
acquisition of a supplier for the two remaining tranches, which were filed
and
accepted by the PPUC in a secretarial letter that was entered on
September 22, 2006. On August 24, 2006, Penn made a compliance filing.
OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
exceptions on September 5, 2006. On September 21, 2006, Penn submitted
a revised compliance filing to the PPUC for the Residential Group and Small
Commercial Group as a result of an agreement between Penn, OCA and OSBA. The
PPUC approved proposed rates for the large commercial and industrial customers
at the PPUC Public meeting on October 19, 2006, and found that the results
of the competitive solicitation process were consistent with prevailing market
prices.
On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
April 28, 2006 and May 4, 2006, which together decided the issues
associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
impose a geographic limitation on the sources of alternative energy credits.
On
June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
ruling on the method by which alternative energy credits may be acquired and
traded. Penn is unable to predict the outcome of this appeal.
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 CBP 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.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio CBP, 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. Under the procedural
schedule approved in this case, FES expected an initial decision to be issued
in
late January 2007. However, on July 14, 2006, the Chief Judge granted the
joint
motion of FES and the Trial Staff to appoint a settlement judge in this
proceeding and the procedural schedule was suspended pending settlement
discussions among the parties. A settlement conference was held on September
5,
2006. FES and the Ohio Companies, Penn, and the PUCO, along
with other
parties, reached an agreement to settle the case. The settlement was filed
with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. Initial comments to the settlement are due
by
November 6, 2006.
The
terms of the
settlement provide for modification of both the Ohio and Penn power supply
agreements with FES. Under the Ohio power supply agreement, separate rates
are
established for the Ohio Companies’ PLR requirements, special retail contracts
requirements, wholesale contract requirements, and interruptible buy-through
retail load requirements. For their PLR and special retail contract
requirements, the Ohio Companies will pay FES no more than the lower of (i)
the
sum of the retail generation charge, the rate stabilization charge, the fuel
recovery mechanism charge, and FES’ actual incremental fuel costs for such
sales; or (ii) the wholesale price cap. Different wholesale price caps are
imposed for PLR sales, special retail contracts, and wholesale contracts.
The
wholesale price for interruptible buy-through retail load requirements is
limited to the actual spot price of power obtained by FES to provide this
power.
The Ohio Companies have recognized the estimated additional amount payable
to
FES for power supplied during the nine months ended September 30, 2006. The
wholesale rate charged by FES under the Penn power supply agreement will
be no
greater than the generation component of charges for retail PLR load in
Pennsylvania. The FERC is expected to act on this case by the end of the
fourth
quarter of 2006.
As
a result of
Penn’s PLR competitive solicitation process approved by the PPUC, FES was
selected as the winning bidder for a number of the tranches for individual
customer classes. The balance of the tranches will be supplied by unaffiliated
power suppliers. On October 2, 2006, FES filed an application with FERC under
Section 205 of the Federal Power Act for authorization to make these affiliate
sales to Penn. Interventions or protests were due on this filing on October
23,
2006. Penn was the only party to file an intervention in this proceeding.
The
FERC is expected to act on this filing on or before December 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 only 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 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 ($400 million of which is expected to be spent in 2007 with the
primary portion of the remaining $1.1 billion expected to be spent in 2008
and
2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power
Corporation under which Bechtel will engineer, procure, and construct air
quality control systems for the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement with
B&W. The above requirements will be the responsibility of FGCO.
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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
FirstEnergy companies also are defending six separate complaint cases before
the
PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of
their
insured. In each of these three 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 sixth case involves the claim of a non-customer seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003. That case has been dismissed. On
March 7,
2006, the PUCO issued a ruling, based on motions filed by the parties,
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 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.
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
that provide their service. The PUCO denied all other motions for rehearing.
The
plaintiffs in each case have since filed an amended complaint and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have been
set for hearing on October 16, 2007.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
County Common Pleas Court seeking reimbursement for claims paid to numerous
insureds who allegedly suffered losses as a result of the August 14, 2003
outages. All of the insureds appear to be non-customers. The plaintiff insurance
companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
the Ohio Companies and Penn were served on October 27, 2006, and expect to
seek summary dismissal of these cases based on the prior court rulings noted
above. No estimate of potential liability is available for any of these
cases.
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-
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 the Perry Nuclear
Power Plant (12.58%), the transfer included the OE Companies’ prior owned
interests in Beaver Valley Unit 1 (100%), Beaver Valley Unit 2
(33.96%) and the Perry Nuclear Power Plant (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 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.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments
that FENOC had made to improve the performance at the Perry Nuclear Power 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 Nuclear Power 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
the
now repealed 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. On October 18, 2006, the Ohio Supreme Court transferred this
case to a Tuscarawas County Common Pleas Court judge due to concerns over
potential class membership by the Jefferson County Common Pleas
Court.
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. Both filings were
consolidated for hearing and decision. 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.
On
May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
complaint and approving the related tariffs, thus affirming OE’s entitlement to
recovery of its transition charges.
The City of Huron
filed an application for rehearing of the PUCO’s decision on June 9, 2006
and OE filed a memorandum in opposition to that application on June 19,
2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
City of Huron has taken no further action and the period for filing an appeal
has expired.
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
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In September 2006, the SEC issued SAB 108, which provides interpretive guidance
on how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments will
need to be reconsidered using both the rollover and iron curtain methods. This
guidance will be effective for OE in the fourth quarter of 2006. OE does not
expect this Statement to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
OE is currently evaluating the impact of this Statement on its financial
statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for OE as of December 31, 2006. OE is currently
evaluating the impact of this Statement on its financial
statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. OE is currently
evaluating the impact of this Statement.
THE
CLEVELAND ELECTRIC ILLUMINATING
COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE
INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
515,923
|
|
$
|
526,421
|
|
$
|
1,356,104
|
|
$
|
1,408,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
12,748
|
|
|
24,701
|
|
|
39,724
|
|
|
64,138
|
|
Purchased
power
|
|
|
229,779
|
|
|
129,640
|
|
|
531,490
|
|
|
411,366
|
|
Nuclear
operating costs
|
|
|
-
|
|
|
26,252
|
|
|
-
|
|
|
121,765
|
|
Other
operating costs
|
|
|
81,510
|
|
|
89,475
|
|
|
222,841
|
|
|
227,759
|
|
Provision
for
depreciation
|
|
|
17,524
|
|
|
36,100
|
|
|
45,775
|
|
|
100,602
|
|
Amortization
of regulatory assets
|
|
|
38,826
|
|
|
68,455
|
|
|
99,832
|
|
|
177,497
|
|
Deferral
of
new regulatory assets
|
|
|
(39,060
|
)
|
|
(60,519
|
)
|
|
(101,283
|
)
|
|
(126,508
|
)
|
General
taxes
|
|
|
34,228
|
|
|
40,054
|
|
|
100,808
|
|
|
115,546
|
|
Total
expenses
|
|
|
375,555
|
|
|
354,158
|
|
|
939,187
|
|
|
1,092,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
140,368
|
|
|
172,263
|
|
|
416,917
|
|
|
316,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
24,715
|
|
|
36,629
|
|
|
76,325
|
|
|
65,826
|
|
Miscellaneous
income (expense)
|
|
|
813
|
|
|
411
|
|
|
6,209
|
|
|
(8,353
|
)
|
Interest
expense
|
|
|
(34,774
|
)
|
|
(31,786
|
)
|
|
(104,140
|
)
|
|
(96,404
|
)
|
Capitalized
interest
|
|
|
836
|
|
|
1,129
|
|
|
2,346
|
|
|
2,012
|
|
Total
other
income (expense)
|
|
|
(8,410
|
)
|
|
6,383
|
|
|
(19,260
|
)
|
|
(36,919
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
131,958
|
|
|
178,646
|
|
|
397,657
|
|
|
279,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
48,496
|
|
|
68,209
|
|
|
150,730
|
|
|
114,679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
83,462
|
|
|
110,437
|
|
|
246,927
|
|
|
164,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
83,462
|
|
$
|
110,437
|
|
$
|
246,927
|
|
$
|
161,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
83,462
|
|
$
|
110,437
|
|
$
|
246,927
|
|
$
|
164,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
loss on available for sale securities
|
|
|
-
|
|
|
(6,574
|
)
|
|
-
|
|
|
(9,144
|
)
|
Income
tax
benefit related to other comprehensive loss
|
|
|
-
|
|
|
2,510
|
|
|
-
|
|
|
3,433
|
|
Other
comprehensive loss, net of tax
|
|
|
-
|
|
|
(4,064
|
)
|
|
-
|
|
|
(5,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
83,462
|
|
$
|
106,373
|
|
$
|
246,927
|
|
$
|
158,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Cleveland
Electric Illuminating Company are an
|
|
integral
part
of these statements.
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING
COMPANY
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
223
|
|
$
|
207
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $6,819,000 and
|
|
|
|
|
|
|
|
$5,180,000,
respectively, for uncollectible accounts)
|
|
|
283,267
|
|
|
268,427
|
|
Associated
companies
|
|
|
63,926
|
|
|
86,564
|
|
Other
|
|
|
24,075
|
|
|
16,466
|
|
Notes
receivable from associated companies
|
|
|
29,184
|
|
|
19,378
|
|
Prepayments
and other
|
|
|
2,290
|
|
|
1,903
|
|
|
|
|
402,965
|
|
|
392,945
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
2,082,224
|
|
|
2,030,935
|
|
Less
-
Accumulated provision for depreciation
|
|
|
808,728
|
|
|
788,967
|
|
|
|
|
1,273,496
|
|
|
1,241,968
|
|
Construction
work in progress
|
|
|
75,127
|
|
|
51,129
|
|
|
|
|
1,348,623
|
|
|
1,293,097
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
940,786
|
|
|
1,057,337
|
|
Investment
in
lessor notes
|
|
|
519,613
|
|
|
564,166
|
|
Other
|
|
|
13,631
|
|
|
12,840
|
|
|
|
|
1,474,030
|
|
|
1,634,343
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521
|
|
|
1,688,966
|
|
Regulatory
assets
|
|
|
854,525
|
|
|
862,193
|
|
Prepaid
pension costs
|
|
|
136,116
|
|
|
139,012
|
|
Property
taxes
|
|
|
63,500
|
|
|
63,500
|
|
Other
|
|
|
26,261
|
|
|
27,614
|
|
|
|
|
2,768,923
|
|
|
2,781,285
|
|
|
|
$
|
5,994,541
|
|
$
|
6,101,670
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
120,556
|
|
$
|
75,718
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
302,588
|
|
|
212,256
|
|
Other
|
|
|
-
|
|
|
140,000
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
103,449
|
|
|
74,993
|
|
Other
|
|
|
5,889
|
|
|
4,664
|
|
Accrued
taxes
|
|
|
106,899
|
|
|
121,487
|
|
Accrued
interest
|
|
|
31,313
|
|
|
18,886
|
|
Lease
market
valuation liability
|
|
|
60,200
|
|
|
60,200
|
|
Other
|
|
|
48,661
|
|
|
61,308
|
|
|
|
|
779,555
|
|
|
769,512
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
79,590,689
shares outstanding
|
|
|
1,355,957
|
|
|
1,354,924
|
|
Retained
earnings
|
|
|
716,077
|
|
|
587,150
|
|
Total
common
stockholder's equity
|
|
|
2,072,034
|
|
|
1,942,074
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,766,195
|
|
|
1,939,300
|
|
|
|
|
3,838,229
|
|
|
3,881,374
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
547,307
|
|
|
554,828
|
|
Accumulated
deferred investment tax credits
|
|
|
21,185
|
|
|
23,908
|
|
Lease
market
valuation liability
|
|
|
562,900
|
|
|
608,000
|
|
Retirement
benefits
|
|
|
83,615
|
|
|
83,414
|
|
Deferred
revenues - electric service programs
|
|
|
57,638
|
|
|
71,261
|
|
Other
|
|
|
104,112
|
|
|
109,373
|
|
|
|
|
1,376,757
|
|
|
1,450,784
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
5,994,541
|
|
$
|
6,101,670
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Cleveland
Electric Illuminating Company
|
|
are
an
integral part of these balance sheets.
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING
COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
246,927
|
|
$
|
164,578
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
45,775
|
|
|
100,602
|
|
Amortization
of regulatory assets
|
|
|
99,832
|
|
|
177,497
|
|
Deferral
of
new regulatory assets
|
|
|
(101,283
|
)
|
|
(126,508
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
179
|
|
|
19,017
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(55,166
|
)
|
|
(67,130
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(9,513
|
)
|
|
14,934
|
|
Accrued
compensation and retirement benefits
|
|
|
2,681
|
|
|
2,997
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
189
|
|
|
(87,567
|
)
|
Materials
and
supplies
|
|
|
-
|
|
|
(13,584
|
)
|
Prepayments
and other current assets
|
|
|
(387
|
)
|
|
(633
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
29,681
|
|
|
(118,908
|
)
|
Accrued
taxes
|
|
|
(14,588
|
)
|
|
27,176
|
|
Accrued
interest
|
|
|
12,427
|
|
|
5,140
|
|
Electric
service prepayment programs
|
|
|
(13,623
|
)
|
|
55,311
|
|
Other
|
|
|
(5,449
|
)
|
|
(26,328
|
)
|
Net
cash
provided from operating activities
|
|
|
237,682
|
|
|
126,594
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
141,056
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
53,369
|
|
Equity
contributions from parent
|
|
|
-
|
|
|
75,000
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
(101,900
|
)
|
Long-term
debt
|
|
|
(118,295
|
)
|
|
(147,789
|
)
|
Short-term
borrowings, net
|
|
|
(58,819
|
)
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(118,000
|
)
|
|
(141,000
|
)
|
Preferred
stock
|
|
|
-
|
|
|
(2,260
|
)
|
Net
cash used
for financing activities
|
|
|
(295,114
|
)
|
|
(123,524
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(89,771
|
)
|
|
(98,053
|
)
|
Loan
repayments from associated companies, net
|
|
|
108,034
|
|
|
89,236
|
|
Investments
in
lessor notes
|
|
|
44,553
|
|
|
32,476
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
-
|
|
|
376,309
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
-
|
|
|
(398,077
|
)
|
Other
|
|
|
(5,368
|
|
|
(4,951
|
)
|
Net
cash
provided from (used for) investing activities
|
|
|
57,448
|
|
|
(3,060
|
)
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
16
|
|
|
10
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
207
|
|
|
197
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
223
|
|
$
|
207
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Cleveland
Electric Illuminating Company
|
|
are
an
integral part of these statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of The
Cleveland Electric Illuminating Company:
We
have reviewed the
accompanying consolidated balance sheet of The Cleveland Electric Illuminating
Company and its subsidiaries as of September 30, 2006, and the related
consolidated statements of income and comprehensive income for each of the
three-month and nine-month periods ended September 30, 2006 and 2005 and the
consolidated statements of cash flows for the nine-month periods ended September
30, 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.
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 and the Company’s change in its method of
accounting for the consolidation of variable interest entities as of December
31, 2003 as discussed in Note 6 to those consolidated financial statements]
dated February 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
October
31,
2006
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
CEI
is a wholly
owned, electric utility subsidiary of FirstEnergy. CEI conducts business in
portions of Ohio, providing regulated electric distribution services. CEI also
provides generation services to those customers electing to retain CEI as their
power supplier. CEI’s power supply requirements are primarily provided by FES
-
an affiliated
company.
FirstEnergy
Intra-System Generation Asset Transfers
In 2005, the Ohio Companies and Penn 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
CEI’s leasehold interests in certain of the plants that are currently subject to
sale and leaseback arrangements with non-affiliates.
On October 24, 2005, CEI 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, CEI completed the intra-system transfer of its
ownership interests in the nuclear generation assets to NGC through a sale
at
net book value. 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 CEI’s comparative earnings results with reductions in
both revenues and expenses. Revenues are reduced due to the termination of
certain arrangements with FES, under which CEI previously sold its
nuclear-generated KWH to FES and leased its non-nuclear generation assets to
FGCO, a subsidiary of FES. CEI’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. With
respect to CEI's retained leasehold interests in the Bruce Mansfield Plant,
CEI
has continued the fossil generation KWH sales arrangement with FES and continues
to be obligated on the applicable portion of expenses related to those
interests. In addition, CEI receives interest income on associated company
notes
receivable from the transfer of its generation net assets. FES continues to
provide CEI’s PLR requirements under revised purchased power arrangements
covering the three-year period beginning January 1, 2006 (see Regulatory
Matters).
The effects on CEI’s results of operations in the third quarter and nine months
ended September 30, 2006 compared to the same periods of 2005 from the
generation asset transfers (also reflecting CEI's retained leasehold interests
discussed above) are summarized in the following table:
Intra-System
Generation Asset Transfers
|
Income
Statement Effects
|
|
Three
Months
|
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(15)
|
|
|
$
|
(44)
|
|
Nuclear-generated
KWH sales
|
(b)
|
|
(80)
|
|
|
|
(190)
|
|
Total
-
Revenues Effect
|
|
|
(95)
|
|
|
|
(234)
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(10)
|
|
|
|
(24)
|
|
Nuclear
operating costs
|
(c)
|
|
(27)
|
|
|
|
(122)
|
|
Provision
for
depreciation
|
(d)
|
|
(16)
|
|
|
|
(48)
|
|
General
taxes
|
(e)
|
|
(3)
|
|
|
|
(11)
|
|
Total
-
Expenses Effect
|
|
|
(56)
|
|
|
|
(205)
|
|
Operating
Income Effect
|
|
|
(39)
|
|
|
|
(29)
|
|
Other
Income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
14
|
|
|
|
44
|
|
Nuclear
decommissioning trust earnings
|
(g)
|
|
(23)
|
|
|
|
(27)
|
|
Capitalized
interest
|
(h)
|
|
(1)
|
|
|
|
(1)
|
|
Total
- Other
Income Effect
|
|
|
(10)
|
|
|
|
16
|
|
Income
taxes
|
(i)
|
|
(20)
|
|
|
|
(5)
|
|
Net
Income
Effect
|
|
$
|
(29)
|
|
|
$
|
(8)
|
|
|
|
|
|
|
|
|
|
|
(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.
|
Results
of Operations
Earnings
on common
stock in the third quarter of 2006 decreased to $83 million from $110
million in the third quarter of 2005. In the first nine months of 2006,
earnings
on common stock increased to $247 million from $162 million in the same
period of 2005. The change in earnings in both periods reflected the effects
of
the generation asset transfer shown in the table above. Expenses during
the
third quarter of 2006 included $19 million of costs associated with the
proposed FERC settlement (see Note 11) applicable to the first half of
2006. The
increase in the nine month period also reflected the absence of the
$2 million Davis-Besse fine in the first quarter of 2005 and the
$8 million impact of the Ohio tax change implementation in the second
quarter of 2005.
Revenues
Revenues
decreased
by $10 million or 2.0% in the third quarter of 2006 from the same period in
2005. Excluding
the
effects of the generation asset transfers displayed above, revenues increased
$85 million due to a $137 million increase in retail generation sales
revenues and a $41 million reduction in customer shopping incentives, partially
offset by a $76 million decrease in distribution revenues and a $17 million
decrease in non-affiliated wholesale sales. In the first nine months of 2006
compared to the same period in 2005, revenues decreased by $52 million or 3.7%.
Excluding the effects of the generation asset transfers discussed above,
revenues increased $182 million due to a $331 million increase in retail
generation sales revenues and an $88 million reduction in customer shopping
incentives, partially offset by a $182 million decrease in distribution
revenues and a $55 million decrease in non-affiliated wholesale
sales.
The
non-affiliated
wholesale sales revenues decreases for the third quarter and the first nine
months of 2006 compared with the same periods in 2005 resulted from the December
2005 cessation of the MSG sales arrangements under CEI’s transition plan. CEI
had been required to provide the MSG to non-affiliated alternative
suppliers.
Changes
in electric
generation KWH sales and revenues
in the
third quarter and first nine months of 2006 from the corresponding periods
of
2005 are summarized in the following tables.
Changes
in Generation KWH Sales
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
61.6
|
%
|
|
52.9
|
%
|
Wholesale
|
|
|
(81.6)
|
%
|
|
(75.5)
|
%
|
Net
Decrease in Generation Sales
|
|
|
(26.8)
|
%
|
|
(21.1)
|
%
|
Changes
in Generation Revenues
|
|
|
Three
Months
|
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
(In
millions)
|
|
Retail
Generation:
|
|
|
|
|
|
|
|
Residential
|
|
$
|
55
|
|
$
|
132
|
|
Commercial
|
|
|
48
|
|
|
118
|
|
Industrial
|
|
|
34
|
|
|
81
|
|
Total
Retail
Generation
|
|
|
137
|
|
|
331
|
|
Wholesale*
|
|
|
(17
|
)
|
|
(55
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
120
|
|
$
|
276
|
|
*Excludes
impact of
generation asset transfers related to nuclear generated KWH sales.
Increased
retail
generation revenues for the third quarter of 2006 compared with the same period
of 2005 (as shown in the table above) were due to higher unit prices and
increased KWH sales. The higher unit prices for generation reflected the rate
stabilization charge that became effective in the first quarter of 2006 under
provisions of the RSP and RCP. The increase in generation KWH sales resulted
from decreased customer shopping. Generation services provided by alternative
suppliers as a percent of total sales delivered in CEI's service area decreased
by: residential - 62.4 percentage points, commercial - 46.1 percentage points
and industrial - 9.8 percentage points. The decreased shopping resulted from
certain alternative energy suppliers terminating their supply arrangements
with
CEI's shopping customers in the fourth quarter of 2005.
Increased
retail
generation revenues in the first nine months of 2006 compared with the same
period in 2005 were due to the reasons discussed above. The increase in
generation KWH sales reflected a similar decrease in customer shopping also
as
discussed above. This resulted in similar percentage decreases in the first
nine
months of 2006 in generation services provided by alternative suppliers as
a
percentage of total sales deliveries in CEI's service area (residential - 60.9
percentage points, commercial - 42.9 percentage points and industrial - 8.3
percentage points).
Changes
in
distribution KWH deliveries and revenues
in the
third quarter and first nine months of 2006 from the corresponding periods
of
2005 are summarized in the following tables.
Changes
in Distribution KWH Sales
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
(6.3)
|
%
|
(4.7)
|
%
|
|
|
Commercial
|
|
(3.5)
|
%
|
(4.0)
|
%
|
|
|
Industrial
|
|
1.2
|
%
|
(1.3)
|
%
|
|
|
Net
Decrease in Distribution Deliveries
|
|
(2.3)
|
%
|
(3.0)
|
%
|
|
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Nine
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Residential
|
|
$
|
(25)
|
|
$
|
(46)
|
Commercial
|
|
|
(29)
|
|
|
(74)
|
Industrial
|
|
|
(22)
|
|
|
(62)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(76)
|
|
$
|
(182)
|
Lower
distribution
revenues shown in the table above for the third quarter and first nine months
of
2006 primarily
reflected
lower unit prices and decreased KWH deliveries. The lower unit prices reflected
the completion of the generation-related transition cost recovery under CEI’s
transition plan in 2005, partially offset by increased transmission rates to
recover MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). The
lower
KWH distribution deliveries to residential and commercial customers were
primarily due to milder weather conditions in the third quarter and first nine
months of 2006, compared to the same periods of 2005.
Under
the Ohio
transition plan, CEI provided incentives to customers to encourage switching
to
alternative energy providers, reducing CEI's revenues. These revenue reductions,
which were deferred for future recovery and did not affect earnings, ceased
in
2006, resulting in a $41 million revenue increase for the third quarter of
2006
and an $88 million increase for the first nine months of 2006 compared to the
same periods of 2005, as discussed above.
Expenses
Total
expenses
increased by $22 million in the third quarter of 2006 and decreased by
$159 million in the first nine months of 2006 from the same periods of
2005. The change in both periods was impacted by the effects of the
generation asset transfers shown in the table above. Excluding the asset
transfer effects, the following table presents changes from the prior year
by
expense category:
Expenses
- Changes
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
costs
|
|
$
|
(1
|
)
|
$
|
-
|
|
Purchased
power costs
|
|
|
100
|
|
|
120
|
|
Other
operating costs
|
|
|
(8
|
)
|
|
(5
|
)
|
Provision
for
depreciation
|
|
|
(3
|
)
|
|
(7
|
)
|
Amortization
of regulatory assets
|
|
|
(30
|
)
|
|
(78
|
)
|
Deferral
of
new regulatory assets
|
|
|
21
|
|
|
25
|
|
General
taxes
|
|
|
(2
|
)
|
|
(3
|
)
|
Net
increase in expenses
|
|
$
|
77
|
|
$
|
52
|
|
Higher
purchased
power costs in the third quarter and the first nine months of 2006 as compared
to the same periods of 2005 resulted from increased KWH purchases and higher
unit prices. Greater KWH purchases primarily reflected higher retail generation
sales requirements and the higher unit prices are primarily due to the current
power supply agreement with FES. Lower other operating costs in both periods
of
2006 compared with the same periods in 2005 reflected the absence in 2006
of
transmission expenses related to the 2005 competitive retail energy supplier
reimbursements which were discontinued at the end of 2005. In addition,
decreased employee and contractor costs resulted from lower storm-related
expenses and decreased contractor costs for vegetation management. Partially
offsetting the lower other operating costs were greater transmission expenses
in
both periods that primarily relate to MISO Day 2 operations that began on
April 1, 2005.
Excluding the effects of the generation asset transfers, the
depreciation
decrease in the first nine months of 2006 compared to 2005 was primarily
attributable to a second quarter 2006 pretax credit adjustment of $6.5 million
($4 million net of tax) applicable to prior periods. Lower
amortization
of regulatory assets in both periods of 2006 reflected the completion of
generation-related transition cost amortization under CEI’s transition plan,
partially offset by the amortization of deferred MISO costs that are being
recovered in 2006. The
decreased
deferral of new regulatory assets in the third quarter and first nine months
of
2006 compared with the same periods in 2005 was primarily due to the termination
of the shopping incentive deferrals ($41 million and $87 million, respectively)
and lower MISO cost deferrals ($12 million and $16 million, respectively),
partially offset by the deferrals of distribution costs ($16 million and
$44 million, respectively) and fuel costs ($16 million and $34 million,
respectively) under the RCP. The deferral of interest on the unamortized
shopping incentive balances continues under the RCP.
Other
Income
The
change in other
income for both periods reflected the generation asset transfers discussed
above. Excluding the effects of the asset transfer, other income decreased
by $6
million in the third quarter of 2006 as a result of greater interest expense
due
to the absence of refinancing cost reductions recognized in 2005. Excluding
the
effects of the asset transfer, other income increased by $2 million in the
first
nine months of 2006 and was primarily due to a $6 million benefit recognized
in
the second quarter of 2006 related to the sale of the Ashtabula C Plant,
partially offset by increased interest expense in 2006.
Income
Taxes
Income
taxes
decreased by $20 million in the third quarter of 2006 and increased by
$36 million
in
the first nine months of 2006 compared to the same periods of 2005. Excluding
the effects of the generation asset transfer, income taxes were unchanged
in the
third quarter of 2006 and increased by $41 million in first nine months of
2006. The increase in the first nine months of 2006 was primarily due to
an
increase in taxable income, partially offset by the absence in 2006 of $8
million of additional income tax expenses from the implementation of Ohio
tax
legislation changes in the second quarter of 2005.
Preferred
Stock
Dividend Requirements
Preferred
stock
dividend requirements decreased by $3 million in the first nine months of 2006,
compared to the same period last year, as a result of the optional redemption
of
CEI's remaining outstanding preferred stock in 2005.
Capital
Resources and Liquidity
During the remainder of 2006, CEI expects to meet its contractual obligations
with cash from operations, short-term credit arrangements and funds from capital
markets. Thereafter, CEI expects to use a combination of cash from operations
and funds from the capital markets.
Changes
in Cash
Position
As of September 30, 2006, CEI had $223,000 of cash and cash equivalents,
compared with $207,000 as of December 31, 2005. The major sources of changes
in
these balances are summarized below.
Cash
Flows from
Operating Activities
Cash
provided from
operating activities during the first nine months of 2006, compared with the
same period last year, were as follows:
|
|
Nine
Months Ended
September
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings*
|
|
$
|
216
|
|
$
|
274
|
|
Working
capital and other
|
|
|
22
|
|
|
(147
|
)
|
Net
cash
provided from operating activities
|
|
$
|
238
|
|
$
|
127
|
|
*
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. CEI believes that cash earnings is a useful financial measure because
it
provides investors and management with an additional means of evaluating its
cash-based operating performance. Generally, a non-GAAP financial measure is
a
numerical measure of a company’s historical or future financial performance,
financial position, or cash flows that either excludes or includes amounts,
or
is subject to adjustment that has the effect of excluding or including amounts,
that are not normally excluded or included in the most directly comparable
measure calculated and presented in accordance with GAAP. In addition, cash
earnings (non-GAAP) are not defined under GAAP. Management believes presenting
this non-GAAP measure provides useful information to investors in assessing
CEI’s operating performance from a cash perspective without the effects of
material unusual economic events. CEI’s management frequently references these
non-GAAP financial measures in its decision-making, using them to facilitate
historical and ongoing performance comparisons as well as comparisons to the
performance of peer companies. These non-GAAP measures should be considered
in
addition to, and not as a substitute for, their most directly comparable
financial measures prepared in accordance with GAAP.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
Income
(GAAP)
|
|
$
|
247
|
|
$
|
165
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
46
|
|
|
101
|
|
Amortization
of regulatory assets
|
|
|
100
|
|
|
177
|
|
Deferral
of
new regulatory assets
|
|
|
(101)
|
|
|
(127)
|
|
Nuclear
fuel
and capital lease amortization
|
|
|
-
|
|
|
19
|
|
Amortization
of electric service obligation
|
|
|
(14)
|
|
|
(12)
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(
55)
|
|
|
(67)
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(10)
|
|
|
15
|
|
Accrued
compensation and retirement benefits
|
|
|
3
|
|
|
3
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
216
|
|
$
|
274
|
|
Net
cash provided
from operating activities increased by $111 million in the first nine months
of
2006 from the same period last year as a result of a $169 million increase
in working capital and other cash flows, partially offset by a $58 million
decrease in cash earnings described above under "Results of Operations."
The
largest factors contributing to the changes in working capital and other
operating cash flows for the first nine months of 2006 are changes in accounts
receivable related to the 2005 conversion of the CFC receivables financing
($155
million) to on-balance sheet transactions and changes in accounts payable,
offset in part by the absence of funds received in 2005 for prepaid electric
service under the Energy for Education Program.
Cash
Flows from
Financing Activities
Net
cash used for
financing activities increased by $172 million in the first nine months of
2006
from the same period last year. The increase in funds used for financing
activities primarily resulted from a $122 million increase in net preferred
stock and debt redemptions and the absence of a $75 million equity contribution
from FirstEnergy in 2005, partially offset by a $23 million decrease in common
stock dividend payments to FirstEnergy.
CEI
had $29 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and approximately $303 million of short-term
indebtedness as of September 30, 2006. CEI has obtained authorization from
the
PUCO to incur short-term debt of up to $600 million (including the bank
facility and utility money pool described below).
As
of September 30,
2006, CEI had the capability to issue $259 million of additional FMB on the
basis of property additions and retired bonds under the terms of its mortgage
indenture. The issuance of FMB by CEI is subject to a provision 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, CEI is permitted under the
indenture to incur additional secured debt not otherwise permitted by a
specified exception of up to $579 million as of September 30, 2006. CEI has
no restrictions on the issuance of preferred stock.
CFC
is a wholly
owned subsidiary of CEI whose borrowings are secured by customer accounts
receivable purchased from CEI and TE. CFC can borrow up to $200 million under
a
receivables financing arrangement. As a separate legal entity with separate
creditors, CFC would have to satisfy its obligations to creditors before any
of
its remaining assets could be made available to CEI. As of September 30, 2006,
the facility was not drawn.
CEI
has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal amount, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the first nine months of 2006 was
5.09%.
On August 24, 2006, CEI, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec,
FES and ATSI, as Borrowers, have entered into a new $2.75 billion five-year
revolving credit facility which replaced the prior $2 billion credit facility.
FirstEnergy may request an increase in the total commitments available under
the
new facility up to a maximum of $3.25 billion.
Borrowings under
the facility are available to each Commitments
under
the new facility are available until August 24, 2011, unless the lenders
agree, at the request of the Borrowers, to two additional one-year extensions.
Generally, borrowings under the facility must be repaid within 364 days.
Available amounts for each Borrower are subject to a specified sub-limit, as
well as applicable regulatory and other limitations. CEI’s
borrowing
limit under the facility is $250 million subject 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 LOC 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 $450 million as of September 30,
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
September 30, 2006, CEI's debt to total capitalization as defined under the
revolving credit facility was 49%.
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.
CEI’s
access to the
capital markets and the costs of financing are dependent on the ratings of
its
securities and the securities of FirstEnergy. The ratings outlook from S&P
on all such securities is stable. The ratings outlook from Moody's and Fitch
on
all securities is positive.
In April and May of 2006, pollution control notes that were formerly obligations
of CEI were refinanced and became obligations of FGCO and NGC. The proceeds
from
the refinancings were used to repay a portion of FGCO’s and NGC’s associated
company notes payable to CEI. CEI redeemed $117.8 million of pollution
control notes having variable interest rates.
A CEI shelf registration for $550 million of unsecured debt securities was
declared effective by the SEC on October 31, 2006 and remains
unused.
Cash
Flows from
Investing Activities
Net
cash provided
from investing activities increased by $61 million in the first nine months
of
2006 from the same period last year. The change was primarily due to increased
loan repayments from associated companies and the absence of net investments
in
nuclear decommissioning trust funds due to the intra-system nuclear generation
asset transfer.
In
the last quarter
of 2006, CEI’s capital spending is expected to be approximately $35 million.
These cash requirements are expected to be satisfied from internal cash and
short-term credit arrangements. CEI’s capital spending for the period 2006-2010
is expected to be approximately $622 million of which approximately $129 million
applies to 2006.
Off-Balance
Sheet Arrangements
Obligations
not
included on CEI’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant. As of
September 30, 2006, the present value of these operating lease commitments,
net of trust investments, total $95 million.
Outlook
The electric industry continues to transition to a more competitive environment
and all of CEI’s customers can select alternative energy suppliers. CEI
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. CEI has a
continuing responsibility to provide power to those customers not choosing
to
receive power from an alternative energy supplier subject to certain
limits.
Regulatory
Matters
Regulatory assets are costs which have been authorized by the PUCO 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 CEI’s
transition plan. CEI’s regulatory assets as of September 30, 2006 and
December 31, 2005, were $855 million and $862 million,
respectively.
On
October 21, 2003,
the Ohio Companies filed their 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
the
PUCO’s 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 the proceeding as well as the associated entries
on
rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
the PUCO's order with respect to the approval of the rate stabilization charge,
approval of the shopping credits, the granting of interest on shopping credit
incentive deferral amounts, and approval of the Ohio Companies’ financial
separation plan. It remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the competitive
marketplace. The RSP contained a provision that permitted the Ohio Companies
to
withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
have
30 days from the final order or decision to provide notice of termination.
On
July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
a
Proceeding on Remand. In their Request, the Ohio Companies provided notice
of
termination to those provisions of the RSP subject to termination, subject
to
being withdrawn, and also set forth a framework for addressing the Supreme
Court
of Ohio’s findings on customer participation, requesting the PUCO to initiate a
proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
resolution to the issues raised by the Supreme Court of Ohio that is acceptable
to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
considered to be null and void. Separately, the OCC and NOAC also submitted
to
the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
by
the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
to
address the Court’s concern. On September 19, 2006, the PUCO issued an
Entry granting the Ohio Companies’ motion for extension of time to file the
remand proposal. The Ohio Companies filed their RSP Remand CBP on
September 29, 2006. No further proceedings have been scheduled at this
time.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
November 4, 2005, the Ohio Companies filed a supplemental stipulation with
the
PUCO, which constituted an additional component of the RCP filed on
September 9, 2005. Major provisions of the RCP include:
|
·
|
Maintaining
the existing level of base distribution rates through 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 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, 2010 for
CEI;
|
|
|
|
|
·
|
Reducing
the
deferred shopping incentive balances as of January 1, 2006 by up to
$85 million for CEI by accelerating the application of its
accumulated cost of removal regulatory liability; and
|
|
|
|
|
·
|
Deferring
and
capitalizing (for recovery over a 25-year period) increased fuel
costs
above the amount collected through the Ohio Companies’ fuel recovery
mechanism.
|
The following table provides CEI’s estimated amortization of regulatory
transition costs and deferred shopping incentives (including associated carrying
charges) under the RCP for the period 2006 through 2010:
Amortization
|
|
|
|
Period
|
|
Amortization
|
|
|
|
(In
millions)
|
|
2006
|
|
$
|
96
|
|
2007
|
|
|
113
|
|
2008
|
|
|
130
|
|
2009
|
|
|
211
|
|
2010
|
|
|
264
|
|
Total
Amortization
|
|
$
|
814
|
|
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. 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 notices of appeal with the
Supreme Court of Ohio alleging various errors made by the PUCO in its order
approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
and the Ohio Companies. The Appellees’ Merit Briefs were filed on
August 24, 2006 and the Appellants’ Reply Briefs were filed on
September 21 2006. The OCC filed an amicus brief on August 4, 2006,
which the Ohio Companies moved to strike as improperly filed. The Supreme Court
denied the Ohio Companies’ motion on October 18, 2006.
On December 30, 2004, CEI 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 recovered from January 1 through June 30, 2006 were approximately
$23.5 million. That amount included the recovery of a portion of the 2005
deferred MISO expenses as described below. On April 27, 2006, CEI filed the
annual update rider to determine revenues ($50 million) from July 2006
through June 2007. The filed rider went into effect on July 1,
2006.
The second application sought authority to defer costs associated with
transmission and ancillary service related costs incurred during the period
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. On
January 20,
2006, the OCC sought rehearing of the PUCO’s 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. 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
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 were heard on May 10, 2006. The Ohio Companies are
awaiting a final ruling from the Ohio Supreme Court, which is expected before
the end of 2006.
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 CBP 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.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio CBP, 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. Under the procedural
schedule approved in this case, FES expected an initial decision to be issued
in
late January 2007. However, on July 14, 2006, the Chief Judge granted the
joint
motion of FES and the Trial Staff to appoint a settlement judge in this
proceeding and the procedural schedule was suspended pending settlement
discussions among the parties. A settlement conference was held on September
5,
2006. FES and the Ohio Companies, Penn, and the PUCO, along
with other
parties, reached an agreement to settle the case. The settlement was filed
with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. Initial comments to the settlement are due
by
November 6, 2006.
The
terms of the
settlement provide for modification of both the Ohio and Penn power supply
agreements with FES. Under the Ohio power supply agreement, separate rates
are
established for the Ohio Companies’ PLR requirements, special retail contracts
requirements, wholesale contract requirements, and interruptible buy-through
retail load requirements. For their PLR and special retail contract
requirements, the Ohio Companies will pay FES no more than the lower of
(i) the
sum of the retail generation charge, the rate stabilization charge, the
fuel
recovery mechanism charge, and FES’ actual incremental fuel costs for such
sales; or (ii) the wholesale price cap. Different wholesale price caps
are
imposed for PLR sales, special retail contracts, and wholesale contracts.
The
wholesale price for interruptible buy-through retail load requirements
is
limited to the actual spot price of power obtained by FES to provide this
power.
The Ohio Companies have recognized the estimated additional amount payable
to
FES for power supplied during the nine months ended September 30, 2006.
The
wholesale rate charged by FES under the Penn power supply agreement will
be no
greater than the generation component of charges for retail PLR load in
Pennsylvania. The FERC is expected to act on this case by the end of the
fourth
quarter of 2006.
See Note 11 to the consolidated financial statements for further details
and a complete discussion of regulatory matters in Ohio.
Environmental
Matters
CEI
accrues environmental liabilities when 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 CEI’s determination of environmental liabilities and are
accrued in the period that they are both probable and reasonably
estimable.
Regulation
of
Hazardous Waste-
CEI has been named a PRP at waste disposal sites, which may require cleanup
under the Comprehensive Environmental Response, Compensation and Liability
Act
of 1980. Allegations of disposal of hazardous substances at historical sites
and
the liability involved are often unsubstantiated and subject to dispute;
however, federal law provides that all PRPs for a particular site 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
September 30, 2006, based on estimates of the total costs of cleanup, CEI’s
proportionate responsibility for such costs and the financial ability of
other
unaffiliated entities to pay. Included in Other Noncurrent Liabilities are
accrued liabilities aggregating approximately $1 million as of September
30,
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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
FirstEnergy companies also are defending six separate complaint cases before
the
PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of
their
insured. In each of these three 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 sixth case involves the claim of a non-customer
seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003. That case has been dismissed. On
March 7,
2006, the PUCO issued a ruling, based on motions filed by the parties,
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 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.
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
that provide their service. The PUCO denied all other motions for rehearing.
The
plaintiffs in each case have since filed an amended complaint and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have
been
set for hearing on October 16, 2007.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
County Common Pleas Court seeking reimbursement for claims paid to numerous
insureds who allegedly suffered losses as a result of the August 14, 2003
outages. All of the insureds appear to be non-customers. The plaintiff insurance
companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
the Ohio Companies and Penn were served on October 27, 2006, and expect to
seek summary dismissal of these cases based on the prior court rulings noted
above. No estimate of potential liability is available for any of these
cases.
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.
Other
Legal
Matters
There are various lawsuits, claims (including claims for asbestos exposure)
and
proceedings related to CEI’s normal business operations pending against CEI 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
the
now repealed 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.
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. Both filings
were
consolidated for hearing and decision. 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. On
May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
complaint and approving the related tariffs, thus affirming OE’s entitlement to
recovery of its transition charges. The City of Huron filed an application
for
rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum
in opposition to that application on June 19, 2006. The PUCO denied the
City’s application for rehearing on June 28, 2006. The City of Huron has taken
no further action and the period for filing an appeal has expired.
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
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In September 2006, the SEC issued SAB 108, which provides interpretive guidance
on how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments
will
need to be reconsidered using both the rollover and iron curtain methods.
This
guidance will be effective for CEI in the fourth quarter of 2006. CEI
does
not expect this Statement to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157, that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
CEI is currently evaluating the impact of this Statement on its financial
statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for CEI as of December 31, 2006. CEI is
currently
evaluating the impact of this Statement on its financial
statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. CEI is
currently evaluating the impact of this Statement.
THE
TOLEDO EDISON
COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE
INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
262,837
|
|
$
|
286,960
|
|
$
|
706,412
|
|
$
|
787,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
9,399
|
|
|
16,501
|
|
|
28,799
|
|
|
43,474
|
|
Purchased
power
|
|
|
112,389
|
|
|
73,144
|
|
|
268,468
|
|
|
225,600
|
|
Nuclear
operating costs
|
|
|
19,252
|
|
|
39,207
|
|
|
54,450
|
|
|
145,059
|
|
Other
operating costs
|
|
|
44,253
|
|
|
48,164
|
|
|
124,396
|
|
|
123,823
|
|
Provision
for
depreciation
|
|
|
8,386
|
|
|
18,835
|
|
|
24,723
|
|
|
48,724
|
|
Amortization
of regulatory assets
|
|
|
27,336
|
|
|
39,576
|
|
|
73,909
|
|
|
107,672
|
|
Deferral
of
new regulatory assets
|
|
|
(15,340
|
)
|
|
(19,379
|
)
|
|
(43,186
|
)
|
|
(41,473
|
)
|
General
taxes
|
|
|
13,406
|
|
|
14,159
|
|
|
38,590
|
|
|
41,960
|
|
Total
expenses
|
|
|
219,081
|
|
|
230,207
|
|
|
570,149
|
|
|
694,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
43,756
|
|
|
56,753
|
|
|
136,263
|
|
|
92,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
9,724
|
|
|
22,807
|
|
|
28,449
|
|
|
39,879
|
|
Miscellaneous
expense
|
|
|
(1,933
|
)
|
|
(2,408
|
)
|
|
(6,543
|
)
|
|
(8,810
|
)
|
Interest
expense
|
|
|
(4,940
|
)
|
|
(6,870
|
)
|
|
(13,614
|
)
|
|
(16,847
|
)
|
Capitalized
interest
|
|
|
277
|
|
|
372
|
|
|
835
|
|
|
117
|
|
Total
other
income
|
|
|
3,128
|
|
|
13,901
|
|
|
9,127
|
|
|
14,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
46,884
|
|
|
70,654
|
|
|
145,390
|
|
|
107,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
17,706
|
|
|
28,427
|
|
|
54,834
|
|
|
57,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
29,178
|
|
|
42,227
|
|
|
90,556
|
|
|
50,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
1,161
|
|
|
1,687
|
|
|
3,597
|
|
|
6,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
28,017
|
|
$
|
40,540
|
|
$
|
86,959
|
|
$
|
44,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
29,178
|
|
$
|
42,227
|
|
$
|
90,556
|
|
$
|
50,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
1,379
|
|
|
(4,511
|
)
|
|
432
|
|
|
(6,695
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
498
|
|
|
(1,743
|
)
|
|
156
|
|
|
(2,534
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
881
|
|
|
(2,768
|
)
|
|
276
|
|
|
(4,161
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
30,059
|
|
$
|
39,459
|
|
$
|
90,832
|
|
$
|
46,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Toledo
Edison Company are an integral part of
|
|
these
statements.
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
20
|
|
$
|
15
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
|
|
|
527
|
|
|
2,209
|
|
Associated
companies
|
|
|
46,252
|
|
|
16,311
|
|
Other
|
|
|
3,220
|
|
|
6,410
|
|
Notes
receivable from associated companies
|
|
|
109,972
|
|
|
48,349
|
|
Prepayments
and other
|
|
|
1,134
|
|
|
1,059
|
|
|
|
|
161,125
|
|
|
74,353
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
862,462
|
|
|
824,677
|
|
Less
-
Accumulated provision for depreciation
|
|
|
387,114
|
|
|
372,845
|
|
|
|
|
475,348
|
|
|
451,832
|
|
Construction
work in progress
|
|
|
33,912
|
|
|
33,920
|
|
|
|
|
509,260
|
|
|
485,752
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
382,668
|
|
|
436,178
|
|
Investment
in
lessor notes
|
|
|
169,523
|
|
|
178,798
|
|
Nuclear
plant
decommissioning trusts
|
|
|
60,826
|
|
|
59,209
|
|
Other
|
|
|
1,802
|
|
|
1,781
|
|
|
|
|
614,819
|
|
|
675,966
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576
|
|
|
501,022
|
|
Regulatory
assets
|
|
|
255,869
|
|
|
287,095
|
|
Prepaid
pension costs
|
|
|
34,903
|
|
|
35,566
|
|
Property
taxes
|
|
|
18,047
|
|
|
18,047
|
|
Other
|
|
|
27,159
|
|
|
24,164
|
|
|
|
|
836,554
|
|
|
865,894
|
|
|
|
$
|
2,121,758
|
|
$
|
2,101,965
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
30,000
|
|
$
|
53,650
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
47,214
|
|
|
46,386
|
|
Other
|
|
|
2,946
|
|
|
2,672
|
|
Notes
payable
to associated companies
|
|
|
178,575
|
|
|
64,689
|
|
Accrued
taxes
|
|
|
52,802
|
|
|
49,344
|
|
Lease
market
valuation liability
|
|
|
24,600
|
|
|
24,600
|
|
Other
|
|
|
33,055
|
|
|
40,049
|
|
|
|
|
369,192
|
|
|
281,390
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
Common
stock,
$5 par value, authorized 60,000,000 shares -
|
|
|
|
|
|
|
|
39,133,887
shares outstanding
|
|
|
195,670
|
|
|
195,670
|
|
Other
paid-in
capital
|
|
|
473,924
|
|
|
473,638
|
|
Accumulated
other comprehensive income
|
|
|
4,966
|
|
|
4,690
|
|
Retained
earnings
|
|
|
225,613
|
|
|
189,428
|
|
Total
common
stockholder's equity
|
|
|
900,173
|
|
|
863,426
|
|
Preferred
stock
|
|
|
66,000
|
|
|
96,000
|
|
Long-term
debt
|
|
|
207,660
|
|
|
237,753
|
|
|
|
|
1,173,833
|
|
|
1,197,179
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
195,552
|
|
|
221,149
|
|
Accumulated
deferred investment tax credits
|
|
|
11,217
|
|
|
11,824
|
|
Lease
market
valuation liability
|
|
|
224,950
|
|
|
243,400
|
|
Retirement
benefits
|
|
|
42,740
|
|
|
40,353
|
|
Asset
retirement obligations
|
|
|
26,105
|
|
|
24,836
|
|
Deferred
revenues - electric service programs
|
|
|
25,862
|
|
|
32,606
|
|
Other
|
|
|
52,307
|
|
|
49,228
|
|
|
|
|
578,733
|
|
|
623,396
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
2,121,758
|
|
$
|
2,101,965
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Toledo
Edison Company are an
|
integral
part
of these balance sheets.
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
90,556
|
|
$
|
50,268
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
24,723
|
|
|
48,724
|
|
Amortization
of regulatory assets
|
|
|
73,909
|
|
|
107,672
|
|
Deferral
of
new regulatory assets
|
|
|
(43,186
|
)
|
|
(41,473
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
-
|
|
|
13,816
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(27,114
|
)
|
|
(34,156
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(28,603
|
)
|
|
(4,605
|
)
|
Accrued
compensation and retirement benefits
|
|
|
2,766
|
|
|
3,438
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
(25,069
|
)
|
|
15,962
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(2,124
|
)
|
Prepayments
and other current assets
|
|
|
(75
|
)
|
|
(562
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
1,102
|
|
|
(80,586
|
)
|
Accrued
taxes
|
|
|
3,458
|
|
|
25,257
|
|
Accrued
interest
|
|
|
(709
|
)
|
|
(565
|
)
|
Electric
service prepayment programs
|
|
|
(6,744
|
)
|
|
34,653
|
|
Other
|
|
|
1,716
|
|
|
(22,999
|
)
|
Net
cash
provided from operating activities
|
|
|
66,730
|
|
|
112,720
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
45,000
|
|
Short-term
borrowings, net
|
|
|
113,886
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
(30,000
|
)
|
|
(30,000
|
)
|
Long-term
debt
|
|
|
(53,650
|
)
|
|
(83,754
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
(51,327
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(50,000
|
)
|
|
(10,000
|
)
|
Preferred
stock
|
|
|
(3,597
|
)
|
|
(6,109
|
)
|
Net
cash used
for financing activities
|
|
|
(23,361
|
)
|
|
(136,190
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(45,661
|
)
|
|
(50,119
|
)
|
Loans
to
associated companies, net
|
|
|
(61,549
|
)
|
|
(40,491
|
)
|
Collection
of
principal on long-term notes receivable
|
|
|
53,766
|
|
|
123,546
|
|
Investments
in
lessor notes
|
|
|
9,275
|
|
|
11,927
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
49,744
|
|
|
284,968
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(49,922
|
)
|
|
(306,374
|
)
|
Other
|
|
|
983
|
|
|
13
|
|
Net
cash
provided from (used for) investing activities
|
|
|
(43,364
|
)
|
|
23,470
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
5
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
15
|
|
|
15
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
20
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Toledo
Edison Company are an integral
|
|
part
of these
statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of The
Toledo Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of The Toledo Edison Company and its
subsidiaries as of September 30, 2006, and the related consolidated statements
of income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2006 and 2005 and the consolidated statements of
cash flows for the nine-month periods ended September 30, 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.
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 11 to
those
consolidated financial statements and the Company’s change in its method of
accounting for the consolidation of variable interest entities as of December
31, 2003 as discussed in Note 6 to those consolidated financial statements]
dated February 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
October
31,
2006
|
THE
TOLEDO
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
TE
is a wholly owned
electric utility subsidiary of FirstEnergy. TE conducts business in northwestern
Ohio, providing regulated electric distribution services. TE also provides
generation services to those customers electing to retain TE as their power
supplier. TE’s power supply requirements are provided by FES - an affiliated
company.
FirstEnergy
Intra-System Generation Asset Transfers
In 2005, the Ohio Companies and Penn 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
TE's leasehold interests in certain of the plants that are currently subject
to
sale and leaseback arrangements with non-affiliates.
On October 24, 2005, TE 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, TE completed the intra-system transfer of its
ownership interests in the nuclear generation assets to NGC through a sale
at
net book value. 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 affect
TE’s comparative earnings results with reductions in both revenues and expenses.
Revenues are reduced due to the termination of certain arrangements with FES,
under which TE previously sold its nuclear-generated KWH to FES and leased
its
non-nuclear generation assets to FGCO, a subsidiary of FES. TE’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. With respect to TE's retained leasehold interests
in the Bruce Mansfield Plant and Beaver Valley Unit 2, TE has continued the
generation KWH sales arrangement with FES and its Beaver Valley Unit 2 leased
capacity sales arrangement with CEI, and continues to be obligated on the
applicable portion of expenses related to those interests. In addition, TE
receives interest income on associated company notes receivable from the
transfer of its generation net assets. FES continues to provide TE’s PLR
requirements under revised purchased power arrangements covering the three-year
period beginning January 1, 2006 (see Outlook - Regulatory
Matters).
The effects on TE’s results of operations in the third quarter and nine months
ended September 30, 2006 compared to the same periods of 2005 from the
generation asset transfers are summarized in the following table:
Intra-System
Generation Asset Transfers -
|
Income
Statement Effects
|
|
Three
Months
|
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(4)
|
|
|
$
|
(11)
|
|
Nuclear-generated
KWH sales
|
(b)
|
|
(38)
|
|
|
|
(89)
|
|
Total
-
Revenues Effect
|
|
|
(42)
|
|
|
|
(100)
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(7)
|
|
|
|
(15)
|
|
Nuclear
operating costs
|
(c)
|
|
(21)
|
|
|
|
(83)
|
|
Provision
for
depreciation
|
(d)
|
|
(7)
|
|
|
|
(23)
|
|
General
taxes
|
(e)
|
|
(2)
|
|
|
|
(5)
|
|
Total
-
Expenses Effect
|
|
|
(37)
|
|
|
|
(126)
|
|
Operating
Income Effect
|
|
|
(5)
|
|
|
|
26
|
|
Other
Income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
4
|
|
|
|
12
|
|
Nuclear
decommissioning trust earnings
|
(g)
|
|
(17)
|
|
|
|
(
21)
|
|
Total
- Other
Income Effect
|
|
|
(13)
|
|
|
|
(9)
|
|
Income
taxes
|
(h)
|
|
(7)
|
|
|
|
7
|
|
Net
Income
Effect
|
|
$
|
(11)
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
(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)
Income tax
effect of the above adjustments.
|
Results
of Operations
Earnings
on common
stock in the third quarter of 2006 decreased to $28 million from
$41 million in the third quarter of 2005. This decrease resulted primarily
from lower revenues and lower other income, partially offset by reduced
operating expenses. Expenses during the third quarter of 2006 included
$7 million of costs associated with the proposed FERC settlement (see Note
11) applicable to the first half of 2006. Earnings on common stock in the
first
nine months of 2006 increased to $87 million from $44 million in the
first nine months of 2005. This increase resulted primarily from reduced
operating expenses and the absence of additional income taxes of
$17.5 million from the implementation of Ohio tax legislation changes in
the second quarter of 2005, partially offset by lower revenues and other
income.
The earnings results for both periods included the effects of the generation
asset transfer shown in the table above.
Revenues
Revenues
decreased
by $24 million or 8.4% in the third quarter of 2006 compared with the same
period of 2005, primarily due to the generation asset transfer impact displayed
in the table above. Excluding the effects of the generation asset transfers,
revenues increased $17 million due to a $44 million increase in generation
sales
revenues, a $12 million reduction in customer shopping incentives and a $2
million increase in other revenues, partially offset by decreased distribution
revenues of $41 million.
In
the first nine
months of 2006, revenues decreased by $81 million or 10.3% compared with the
same period of 2005, primarily due to the generation asset transfer impact
displayed in the table above. Excluding the effects of the generation asset
transfers, revenues increased $18 million due to an $88 million increase in
generation sales revenues, a $27 million reduction in customer shopping
incentives and a $3 million increase in other revenues, partially offset by
a $100 million decrease in distribution revenues.
Changes
in electric
generation KWH sales and revenues
in the
third quarter and first nine months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Generation KWH Sales
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
16.1
|
%
|
|
14.0
|
%
|
Wholesale
|
|
|
(63.7
|
)%
|
|
(59.4
|
)%
|
Net
Decrease in Generation Sales
|
|
|
(29.2
|
)%
|
|
(25.8
|
)%
|
Changes
in Generation Revenues
|
|
Three
Months
|
|
Nine
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Retail
Generation:
|
|
|
|
|
|
|
|
Residential
|
|
$
|
24
|
|
$
|
56
|
|
Commercial
|
|
|
15
|
|
|
37
|
|
Industrial
|
|
|
7
|
|
|
16
|
|
Total
Retail
Generation
|
|
|
46
|
|
|
109
|
|
Wholesale*
|
|
|
(2
|
)
|
|
(21
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
44
|
|
$
|
88
|
|
*
Excludes impact of
generation asset transfers related to nuclear-generated KWH sales.
Retail
generation
revenues increased in all customer sectors in the third quarter of 2006 compared
to the corresponding quarter of 2005 (as shown in the table above) due to higher
unit prices and increased KWH sales. The higher unit prices for generation
reflected the rate stabilization charge and the fuel cost recovery rider that
both became effective in the first quarter of 2006 under provisions of the
RSP
and RCP. The increase in generation KWH sales (residential - 65.4%, commercial
-
15.4% and industrial - 2.3%) primarily resulted from decreased customer
shopping. The decreased shopping resulted from certain alternative energy
suppliers terminating their supply arrangements with TE's shopping customers
in
the first quarter of 2006. Generation services provided by alternative suppliers
as a percentage of total sales delivered in TE's franchise area decreased in
all
customer classes by: residential - 38.4
percentage
points,
commercial - 10.3
percentage points
and
industrial - 2.1
percentage
points.
In
the first nine
months of 2006, retail generation revenues increased from the corresponding
period of 2005 for the reasons described above. The decreased customer shopping
resulted in generation KWH sales increases in all customer classes (residential
- 51.4%, commercial - 14.2% and industrial - 3.3%). Similar to the third quarter
of 2006, generation services provided by alternative suppliers as a percentage
of total sales deliveries in TE's franchise area decreased in all customer
classes by: residential - 32.6
percentage
points,
commercial - 10.1
percentage points
and
industrial - 1.9
percentage
points.
Lower
wholesale
revenues in the third quarter and first nine months of 2006 reflected decreased
revenues from non-affiliates ($5 million and $13 million, respectively).
Revenues from associated companies increased $3 million in the third quarter
of
2006, but decreased $7 million for the first nine months of 2006. The
non-affiliated wholesale revenue decreases in 2006 were primarily due to the
December 2005 cessation in the MSG sales arrangements under TE’s transition
plan. TE had been required to provide the MSG to non-affiliated alternative
suppliers. The
higher wholesale
revenues from associated companies in the third quarter of 2006 reflected higher
unit prices and higher volumes sold than in the third quarter of 2005. The
lower
wholesale revenues from associated companies in the first nine months of 2006
reflected lower unit prices due to this year’s absence of expenses related to
the Beaver Valley Unit 2 nuclear refueling outage in April 2005, which were
included as a component of the associated company billing for the 2005
period.
Changes
in
distribution KWH deliveries and revenues
in the
third quarter and first nine months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(6.7
|
)%
|
|
(4.9
|
)%
|
Commercial
|
|
|
(3.8
|
)%
|
|
(4.2
|
)%
|
Industrial
|
|
|
0.1
|
%
|
|
1.3
|
%
|
Net
Decrease in Distribution Deliveries
|
|
|
(2.8
|
)%
|
|
(1.8
|
)%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Residential
|
|
$
|
(19
|
)
|
$
|
(44
|
) |
|
Commercial
|
|
|
(17
|
)
|
|
(46
|
) |
|
Industrial
|
|
|
(5
|
)
|
|
(10
|
) |
|
Net
Decrease in Distribution Revenues
|
|
$
|
(41
|
)
|
$
|
(100
|
) |
|
The
distribution
revenue decreases shown in the table above for the third quarter and first
nine
months of 2006 compared to the same periods of 2005 primarily reflected lower
unit prices in all customer sectors and decreased KWH deliveries to residential
and commercial customers. The lower unit prices resulted from the completion
of
the generation-related transition cost recovery under TE’s transition plan in
2005, partially offset by increased transmission rates to recover MISO costs
beginning in the first quarter of 2006 (see Outlook - Regulatory Matters).
The
lower
KWH deliveries to residential and commercial customers in both periods reflected
the impact of milder weather in the third quarter and the first nine months
of
2006 compared to the same periods of 2005. KWH
deliveries to
industrial customers increased in both periods of 2006 due to increased sales
to
automotive, oil refinery and steel industry customers.
Under
the Ohio
transition plan, TE had provided incentives to customers to encourage switching
to alternative energy providers which reduced TE's revenues. These revenue
reductions, which were deferred for future recovery and did not affect current
period earnings, ceased in 2006, thereby increasing revenues in the third
quarter and first nine months of 2006 by $12 million and $27 million,
respectively. The deferred shopping incentives (Extended RTC) are currently
being recovered under the RCP (see Outlook - Regulatory Matters).
Expenses
Total
expenses
decreased by $11 million and $125 million in the third quarter and the first
nine months of 2006, respectively, from the same periods of 2005 principally
due
to the generation asset transfer effects as shown in the table above. Excluding
the asset transfer effects, the following table presents changes from the prior
year by expense category:
Expenses
- Changes
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
|
|
$
|
(1
|
)
|
$
|
-
|
|
Purchased
power costs
|
|
|
39
|
|
|
43
|
|
Nuclear
operating costs
|
|
|
1
|
|
|
(8
|
)
|
Other
operating costs
|
|
|
(3
|
)
|
|
1
|
|
Provision
for
depreciation
|
|
|
(2
|
)
|
|
-
|
|
Amortization
of regulatory assets
|
|
|
(13
|
)
|
|
(34
|
)
|
Deferral
of
new regulatory assets
|
|
|
4
|
|
|
(2
|
)
|
General
taxes
|
|
|
1
|
|
|
1
|
|
Net increase
in expenses
|
|
$
|
26
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
Lower
fuel expense
in the third quarter of 2006 compared to the third quarter of 2005 was
attributable to the September 2006 turbine outage related to TE’s leasehold
interest in Mansfield Unit 2. Higher purchased power costs in the third quarter
of 2006 compared to the third quarter of 2005 primarily reflected an increase
in
KWH purchased to meet the higher retail generation sales requirements and higher
unit prices associated with the new power supply agreement with FES. The higher
nuclear operating costs associated with TE’s leasehold interest in Beaver Valley
Unit 2 in the third quarter of 2006 reflected costs related to preparations
for
the nuclear refueling outage which began October 2, 2006. Lower other operating
costs in the third quarter of 2006 primarily reflected the absence of consulting
fees related to a 2005 investment tax credit claim.
Higher
purchased
power costs in the first nine months of 2006 compared to the first nine months
of 2005 were due to the same reasons as discussed above in the third quarter
results. Decreased nuclear operating costs in the 2006 nine-month period
resulted from the absence in 2006 of Beaver Valley Unit 2’s 25-day nuclear
refueling outage expenses in April 2005. Higher other operating costs primarily
reflected increased transmission expenses related to MISO Day 2 operations
that
began on April 1, 2005, partially offset by the absence of the consulting fees
in the 2006 period.
Excluding
the
effects of the generation asset transfers, lower depreciation charges in the
third quarter of 2006 compared to the same period of 2005 resulted from the
absence of a one-time adjustment in the third quarter of 2005 for reduced
amortization periods for expenditures on leased generating plants to conform
to
the lease terms.
Lower
amortization
of regulatory assets in both periods of 2006 reflected the completion of
generation-related transition cost recovery under TE’s transition plan,
partially offset by the amortization of deferred MISO costs that are being
recovered in 2006. The net change in deferrals of new regulatory assets in
the
third quarter and first nine months of 2006 primarily resulted from the
deferrals of distribution costs ($6 million and $19 million in the third quarter
and the first nine months of 2006, respectively) and incremental fuel costs
($6
million and $13 million in the third quarter and the first nine months of 2006,
respectively) that began in 2006 under the RCP. This was partially offset by
the
impact of the termination of shopping incentive deferrals in 2006
($13 million and $28 million in the third quarter and the first nine months
of 2006, respectively). The deferral of interest on the unamortized shopping
incentive balances continues under the RCP. MISO transmission cost deferrals
decreased by $3 million and $1 million in the third quarter and the first nine
months of 2006, respectively, compared with the same periods in
2005.
Other
Income
Other
income
decreased $11 million and $5 million in the third quarter and first nine months
of 2006 compared to the same periods of 2005, primarily due to the effects
of
the generation asset transfers. Excluding the asset transfer effects, increases
of $2 million and $4 million in other income were primarily due to
lower interest expense in the third quarter and first nine months of 2006,
respectively, due to redemptions of long-term debt subsequent to the end of
the
third quarter of 2005.
Income
Taxes
Income
taxes
decreased by $10 million in the third quarter of 2006 and $2 million
in the first nine months of 2006 compared to the same periods of 2005. Excluding
the effects of the generation asset transfer, income taxes decreased in the
third quarter of 2006 by $3 million and in the first nine months of 2006 by
$9 million. The decrease in the first nine months of 2006 was primarily due
to the absence in 2006 of $17.5 million of additional income tax expenses
from
the implementation of Ohio tax legislation changes in the second quarter
of 2005
and the subsequent reduction in the tax rates, partially offset by the effect
of
an increase in taxable income.
Preferred
Stock
Dividend Requirements
Lower
preferred
stock dividend requirements in the third quarter of 2006 compared to the same
quarter of 2005 were the result of $30 million of optional preferred stock
redemptions in January 2006. Lower preferred stock dividend requirements in
the
first nine months of 2006 compared to the corresponding 2005 period resulted
from $30 million of optional preferred stock redemptions in July 2005 and
the January 2006 redemption.
Capital
Resources and Liquidity
During
the remainder
of 2006, TE expects to meet its contractual obligations with a combination
of
cash from operations and short-term credit arrangements.
Changes
in Cash
Position
As
of September 30,
2006, TE had $20,000 of cash and cash equivalents, compared with $15,000 as
of
December 31, 2005. The major changes in these balances are summarized below.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities during the first nine months of 2006, compared with the
first nine months of 2005, were as follows:
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings*
|
|
$
|
86
|
|
$
|
140
|
|
Working
capital and other
|
|
|
(19
|
)
|
|
(27
|
)
|
Net
cash
provided from operating activities
|
|
$
|
67
|
|
$
|
113
|
|
|
|
|
|
|
|
|
|
*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. TE
believes that cash
earnings is a useful financial measure because it provides investors and
management with an additional means of evaluating its cash-based operating
performance. Generally,
a
non-GAAP financial measure is a numerical measure of a company’s historical or
future financial performance, financial position, or cash flows that either
excludes or includes amounts, or is subject to adjustment that has the effect
of
excluding or including amounts, that are not normally excluded or included
in
the most directly comparable measure calculated and presented in accordance
with
GAAP. In addition, cash earnings (non-GAAP) are not defined under GAAP.
Management believes presenting this non-GAAP measure provides useful information
to investors in assessing TE’s operating performance from a cash perspective
without the effects of material unusual economic events. TE’s management
frequently references these non-GAAP financial measures in its decision-making,
using them to facilitate historical and ongoing performance comparisons as
well
as comparisons to the performance of peer companies. These non-GAAP measures
should be considered in addition to, and not as a substitute for, their most
directly comparable financial measures prepared in accordance with
GAAP.
|
|
Nine
Months Ended
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
Income
(GAAP)
|
|
$
|
90
|
|
$
|
50
|
|
Non-Cash
Charges (Credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
25
|
|
|
49
|
|
Amortization
of regulatory assets
|
|
|
74
|
|
|
108
|
|
Deferral
of
new regulatory assets
|
|
|
(43
|
)
|
|
(42
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
-
|
|
|
14
|
|
Amortization
of electric service obligation
|
|
|
(7
|
)
|
|
(3
|
)
|
Deferred
rents
and lease market valuation liability
|
|
|
(27
|
)
|
|
(34
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(29
|
)
|
|
(5
|
)
|
Accrued
compensation and retirement benefits
|
|
|
3
|
|
|
3
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
86
|
|
$
|
140
|
|
Net cash provided from operating activities decreased by $46 million in the
first nine months of 2006 from the first nine months of 2005 as a result of
a
$54 million decrease in cash earnings described above under “Results of
Operations” and an $8 million increase from working capital and other
changes.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities decreased to $23 million in the first nine months of 2006
from $136 million in the same period of 2005. The decrease resulted primarily
from a $165 million increase in net short-term borrowings, partially offset
by a
$15 million net increase in preferred stock and long-term debt redemptions
and a
$40 million increase in common stock dividend payments to FirstEnergy in
2006.
TE had $110 million of cash and temporary investments (which included short-term
notes receivable from associated companies) and $179 million of short-term
indebtedness as of September 30, 2006. TE has authorization from the PUCO to
incur short-term debt of up to $500 million through the bank facility and
utility money pool described below. As of September 30, 2006, TE had the
capability to issue $654 million of additional FMB on the basis of property
additions and retired bonds under the terms of its mortgage indenture. Based
upon applicable earnings coverage tests, TE could issue up to $1.0 billion
of preferred stock (assuming no additional debt was issued) as of
September 30, 2006.
On August 24, 2006, TE, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec,
FES and ATSI, as Borrowers, entered into a new $2.75 billion five-year
revolving credit facility that expires in August 2011 which replaced the prior
$2 billion credit facility. FirstEnergy may request an increase in the total
commitments available under the new facility up to a maximum of $3.25 billion.
Commitments under the new facility are available until August 24, 2011,
unless the lenders agree, at the request of the Borrowers, to two additional
one-year extensions. Generally, borrowings under the facility must be repaid
within 364 days. Available amounts for each Borrower are subject to a specified
sub-limit, as well as applicable regulatory and other limitations. TE’s
borrowing limit under the facility is $250 million subject to applicable
regulatory approval.
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.
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
September 30, 2006, TE's debt to total capitalization, as defined under the
revolving credit facility, was 30%.
The revolving credit facility does not contain any provisions that either
restrict TE'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 TE's
credit ratings.
TE
has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal, 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 nine months of 2006 was 5.09%.
TE’s
access to the
capital markets and the costs of financing are dependent on the ratings of
its
securities and the securities of FirstEnergy. 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 TE
were
refinanced and became obligations of FGCO and NGC. The proceeds from the
refinancings were used to repay a portion of FGCO’s and NGC’s associated company
notes payable to TE. With those repayments, TE redeemed pollution control notes
in the aggregate principal amount of $54 million having variable interest
rates.
A TE shelf
registration statement for $300 million of unsecured debt securities was
declared effective by the SEC on October 31, 2006 and remains
unused.
Cash
Flows From
Investing Activities
Net cash used for investing activities was $43 million in the first nine months
of 2006 compared to net cash of $23 million provided from investing activities
in the first nine months of 2005. The change was primarily due to a
decrease
in the
collection of principal on long-term notes receivable and an increase in loans
to associated companies. The decrease in the collection of principal resulted
from the receipt in April 2006 of $54 million from FGCO and NGC following the
pollution control notes refinancing discussed above as compared to the receipt
in May 2005 of a $123 million balloon payment from FGCO for gas-fired combustion
turbines sold in 2001. The decrease in cash receipts and increase in loans
were
partially offset by reduced property additions and net activity for the nuclear
decommissioning trust funds due to the generation asset transfers.
TE’s capital spending for the last quarter of 2006 is expected to be
approximately $16 million. These cash requirements are expected to be
satisfied from a combination of internal cash and short-term credit
arrangements. TE’s capital spending for the period 2006-2010 is expected to be
approximately $236 million, of which approximately $62 million applies
to 2006.
Off-Balance
Sheet Arrangements
Obligations
not
included on TE’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
Unit 2. As of September 30, 2006, the present value of these operating
lease commitments, net of trust investments, totaled $506 million.
Outlook
The electric industry continues to transition to a more competitive environment
and all of TE’s customers can select alternative energy suppliers. TE continues
to deliver power to residential homes and businesses through its existing
distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. TE has a
continuing responsibility to provide power to those customers not choosing
to
receive power from an alternative energy supplier subject to certain
limits.
Regulatory
Matters
Regulatory assets are costs which have been authorized by the PUCO 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 TE’s
regulatory plans. TE’s regulatory assets as of September 30, 2006 and
December 31, 2005 were $256 million and $287 million,
respectively.
On
October 21, 2003,
the Ohio Companies filed their 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
the
PUCO’s 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 the proceeding as well as the associated entries
on
rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
the PUCO's order with respect to the approval of the rate stabilization charge,
approval of the shopping credits, the granting of interest on shopping credit
incentive deferral amounts, and approval of the Ohio Companies’ financial
separation plan. It remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the competitive
marketplace. The RSP contained a provision that permitted the Ohio Companies
to
withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
have
30 days from the final order or decision to provide notice of termination.
On
July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
a
Proceeding on Remand. In their Request, the Ohio Companies provided notice
of
termination to those provisions of the RSP subject to termination, subject
to
being withdrawn, and also set forth a framework for addressing the Supreme
Court
of Ohio’s findings on customer participation, requesting the PUCO to initiate a
proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
resolution to the issues raised by the Supreme Court of Ohio that is acceptable
to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
considered to be null and void. Separately, the OCC and NOAC also submitted
to
the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
by
the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
to
address the Court’s concern. On September 19, 2006, the PUCO issued an
Entry granting the Ohio Companies’ Motion for extension of time to file the
remand proposal. The Ohio Companies filed their RSP Remand CBP on
September 29, 2006. No further proceedings have been scheduled at this
time.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
November 4, 2005, the Ohio Companies filed a supplemental stipulation with
the
PUCO, which constituted an additional component of the RCP filed on September
9,
2005. Major provisions of the RCP include:
|
·
|
Maintaining
the existing level of base distribution rates through December 31,
2008 for TE;
|
|
·
|
Deferring
and
capitalizing for future recovery (over a 25-year period) with carrying
charges certain distribution costs to be incurred by all 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
TE;
|
|
·
|
Reducing
the
deferred shopping incentive balances as of January 1, 2006 by up to
$45 million for TE 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. 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.
|
The following table provides TE’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
|
|
$
|
87
|
|
2007
|
|
|
90
|
|
2008
|
|
|
112
|
|
Total
Amortization
|
|
$
|
289
|
|
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. 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 notices of appeal with the
Supreme Court of Ohio alleging various errors made by the PUCO in its order
approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
granted by the Supreme Court on June 8, 2006. The Appellant’s Merit Briefs were
filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
and
the Ohio Companies. The Appellees’ Merit Briefs were filed on August 24,
2006 and the Appellants’ Reply Briefs were filed on September 21 2006. The
OCC filed an amicus brief on August 4, 2006, which the Ohio Companies moved
to strike as improperly filed. The Supreme Court denied the Ohio Companies’
motion on October 18, 2006.
On December 30, 2004, TE 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. TE
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 recovered
from
January 1 through June 30, 2006 were approximately $6.5 million. That
amount included the recovery of a portion of the 2005 deferred MISO expenses
as
described below. On April 27, 2006, the Ohio Companies filed the annual
update rider to determine revenues ($139 million) from July 2006 through
June 2007 ($19 million for TE). The filed rider went into effect on July 1,
2006.
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. 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. 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
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 were heard on May 10, 2006. The Ohio Companies are
awaiting a final ruling from the Ohio Supreme Court, which is
expected before the end of 2006.
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 CBP 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.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio CBP, 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. Under the procedural
schedule approved in this case, FES expected an initial decision to be issued
in
late January 2007. However, on July 14, 2006, the Chief Judge granted the
joint
motion of FES and the Trial Staff to appoint a settlement judge in this
proceeding and the procedural schedule was suspended pending settlement
discussions among the parties. A settlement conference was held on September
5,
2006. FES and the Ohio Companies, Penn, and the PUCO, along
with other
parties, reached an agreement to settle the case. The settlement was filed
with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. Initial comments to the settlement are due
by
November 6, 2006.
The
terms of the
settlement provide for modification of both the Ohio and Penn power supply
agreements with FES. Under the Ohio power supply agreement, separate rates
are
established for the Ohio Companies’ PLR requirements, special retail contracts
requirements, wholesale contract requirements, and interruptible buy-through
retail load requirements. For their PLR and special retail contract
requirements, the Ohio Companies will pay FES no more than the lower of
(i) the
sum of the retail generation charge, the rate stabilization charge, the
fuel
recovery mechanism charge, and FES’ actual incremental fuel costs for such
sales; or (ii) the wholesale price cap. Different wholesale price caps
are
imposed for PLR sales, special retail contracts, and wholesale contracts.
The
wholesale price for interruptible buy-through retail load requirements
is
limited to the actual spot price of power obtained by FES to provide this
power.
The Ohio Companies have recognized the estimated additional amount payable
to
FES for power supplied during the nine months ended September 30, 2006.
The
wholesale rate charged by FES under the Penn power supply agreement will
be no
greater than the generation component of charges for retail PLR load in
Pennsylvania. The FERC is expected to act on this case by the end of the
fourth
quarter of 2006.
See Note 11 to the consolidated financial statements for further details
and a complete discussion of regulatory matters in Ohio.
Environmental
Matters
TE
accrues
environmental liabilities only 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 TE’s determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
Regulation
of
Hazardous Waste
TE
has been named a PRP at waste
disposal sites, which may require cleanup under the Comprehensive Environmental
Response, Compensation and Liability Act of 1980. Allegations of disposal
of
hazardous substances at historical sites and the liability involved are often
unsubstantiated and subject to dispute; however, federal law provides that
all
PRPs for a particular site 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 September 30, 2006, based on estimates
of
the total costs of cleanup, TE’s proportionate responsibility for such costs and
the financial ability of other unaffiliated entities to pay. Included in
Other
Noncurrent Liabilities are accrued liabilities aggregating approximately
$0.2 million as of September 30, 2006.
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 TE’s normal business operations pending against TE. 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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
FirstEnergy companies also are defending six separate complaint cases before
the
PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various
insurance carriers either in their own name as subrogees or in the name of
their
insured. In each of these three 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 sixth case involves the claim of a non-customer
seeking
reimbursement for losses incurred when its store was burglarized on
August 14, 2003. That case has been dismissed. On
March 7,
2006, the PUCO issued a ruling, based on motions filed by the parties,
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 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.
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
that provide their service. The PUCO denied all other motions for rehearing.
The
plaintiffs in each case have since filed an amended complaint and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have
been
set for hearing on October 16, 2007.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
County Common Pleas Court seeking reimbursement for claims paid to numerous
insureds who allegedly suffered losses as a result of the August 14, 2003
outages. All of the insureds appear to be non-customers. The plaintiff insurance
companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
the Ohio Companies and Penn were served on October 27, 2006, and expect to
seek summary dismissal of these cases based on the prior court rulings noted
above. No estimate of potential liability is available for any of these
cases.
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.
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
the
now repealed 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.
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. Both filings were
consolidated for hearing and decision. 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. On
May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
complaint and approving the related tariffs, thus affirming OE’s entitlement to
recovery of its transition charges. The City of Huron filed an application
for
rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum
in opposition to that application on June 19, 2006. The PUCO denied the
City’s application for rehearing on June 28, 2006. The City of Huron has taken
no further action and the period for filing an appeal has expired.
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
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In
September 2006,
the SEC issued SAB 108, which provides interpretive guidance on how registrants
should quantify financial statement misstatements. There is currently diversity
in practice, with the two commonly used methods to quantify misstatements being
the “rollover” method (which primarily focuses on the income statement impact of
misstatements) and the “iron curtain” method (which focuses on the balance sheet
impact). SAB 108 requires registrants to use a dual approach whereby both of
these methods are considered in evaluating the materiality of financial
statement errors. Prior materiality assessments will need to be reconsidered
using both the rollover and iron curtain methods. This guidance will be
effective for TE in the fourth quarter of 2006. TE
does not expect
this Statement to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In
September 2006,
the FASB issued SFAS 157 that establishes how companies should measure fair
value when they are required to use a fair value measure for recognition or
disclosure purposes under GAAP. This Statement addresses the need for increased
consistency and comparability in fair value measurements and for expanded
disclosures about fair value measurements. The key changes to current practice
are: (1) the definition of fair value which focuses on an exit price rather
than
entry price; (2) the methods used to measure fair value such as emphasis that
fair value is a market-based measurement, not an entity-specific measurement,
as
well as the inclusion of an adjustment for risk, restrictions and credit
standing; and (3) the expanded disclosures about fair value
measurements.
This
Statement is
effective for financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those years. TE is currently
evaluating the impact of this Statement on its financial statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In
September 2006,
the FASB issued SFAS 158, which requires companies to recognize a net liability
or asset to report the overfunded or underfunded status of their defined benefit
pension and other postretirement benefit plans on their balance sheets and
recognize changes in funded status in the year in which the changes occur
through other comprehensive income. The funded status to be measured is the
difference between plan assets at fair value and the benefit obligation. This
Statement requires that gains and losses and prior service costs or credits,
net
of tax, that arise during the period be recognized as a component of other
comprehensive income and not as components of net periodic benefit cost.
Additional information should also be disclosed in the notes to the financial
statements about certain effects on net periodic benefit cost for the next
fiscal year that arise from delayed recognition of the gains or losses, prior
service costs or credits, and transition asset or obligation. Upon the initial
application of this Statement and subsequently, an employer should continue
to
apply the provisions in Statements 87, 88 and 106 in measuring plan assets
and
benefit obligations as of the date of its statement of financial position and
in
determining the amount of net periodic benefit cost. This Statement is effective
for TE as of December 31, 2006. TE
is currently
evaluating the impact of this Statement on its financial
statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. TE is currently
evaluating the impact of this Statement.
PENNSYLVANIA
POWER
COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF
INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
88,700
|
|
$
|
145,540
|
|
$
|
252,069
|
|
$
|
414,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
-
|
|
|
6,205
|
|
|
-
|
|
|
17,351
|
|
Purchased
power
|
|
|
60,490
|
|
|
42,242
|
|
|
171,759
|
|
|
131,948
|
|
Nuclear
operating costs
|
|
|
-
|
|
|
16,997
|
|
|
-
|
|
|
56,710
|
|
Other
operating costs
|
|
|
16,448
|
|
|
19,030
|
|
|
44,776
|
|
|
48,541
|
|
Provision
for
depreciation
|
|
|
2,383
|
|
|
3,847
|
|
|
6,509
|
|
|
11,351
|
|
Amortization
of regulatory assets
|
|
|
-
|
|
|
9,784
|
|
|
3,411
|
|
|
29,499
|
|
General
taxes
|
|
|
6,098
|
|
|
6,836
|
|
|
17,602
|
|
|
19,752
|
|
Total
expenses
|
|
|
85,419
|
|
|
104,941
|
|
|
244,057
|
|
|
315,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
3,281
|
|
|
40,599
|
|
|
8,012
|
|
|
99,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
3,468
|
|
|
698
|
|
|
10,319
|
|
|
475
|
|
Interest
expense
|
|
|
(1,461
|
)
|
|
(2,371
|
)
|
|
(6,823
|
)
|
|
(7,477
|
)
|
Capitalized
interest
|
|
|
62
|
|
|
1,665
|
|
|
144
|
|
|
4,508
|
|
Total
other
income (expense)
|
|
|
2,069
|
|
|
(8
|
)
|
|
3,640
|
|
|
(2,494
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
5,350
|
|
|
40,591
|
|
|
11,652
|
|
|
96,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
2,117
|
|
|
17,551
|
|
|
4,924
|
|
|
42,907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
3,233
|
|
|
23,040
|
|
|
6,728
|
|
|
53,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
156
|
|
|
156
|
|
|
467
|
|
|
1,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
3,077
|
|
$
|
22,884
|
|
$
|
6,261
|
|
$
|
52,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
36
|
|
$
|
24
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $1,135,000 and $1,087,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
37,978
|
|
|
44,555
|
|
Associated
companies
|
|
|
86,656
|
|
|
115,441
|
|
Other
|
|
|
1,778
|
|
|
2,889
|
|
Notes
receivable from associated companies
|
|
|
1,851
|
|
|
1,699
|
|
Restricted
cash
|
|
|
-
|
|
|
78,248
|
|
Prepayments
and other
|
|
|
12,744
|
|
|
8,747
|
|
|
|
|
141,043
|
|
|
251,603
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
371,575
|
|
|
359,069
|
|
Less
-
Accumulated provision for depreciation
|
|
|
132,749
|
|
|
129,118
|
|
|
|
|
238,826
|
|
|
229,951
|
|
Construction
work in progress
|
|
|
3,865
|
|
|
3,775
|
|
|
|
|
242,691
|
|
|
233,726
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
275,924
|
|
|
283,248
|
|
Other
|
|
|
350
|
|
|
351
|
|
|
|
|
276,274
|
|
|
283,599
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Prepaid
pension costs
|
|
|
43,462
|
|
|
42,243
|
|
Other
|
|
|
1,794
|
|
|
3,829
|
|
|
|
|
45,256
|
|
|
46,072
|
|
|
|
|
|
|
|
|
|
|
|
$
|
705,264
|
|
$
|
815,000
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
15,474
|
|
$
|
69,524
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
1,607
|
|
|
12,703
|
|
Other
|
|
|
19,000
|
|
|
-
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
18,194
|
|
|
73,444
|
|
Other
|
|
|
1,581
|
|
|
1,828
|
|
Accrued
taxes
|
|
|
20,629
|
|
|
28,632
|
|
Accrued
interest
|
|
|
1,075
|
|
|
1,877
|
|
Other
|
|
|
7,484
|
|
|
8,086
|
|
|
|
|
85,044
|
|
|
196,094
|
|
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
|
|
|
43,268
|
|
|
37,097
|
|
Total
common
stockholder's equity
|
|
|
303,104
|
|
|
296,933
|
|
Preferred
stock
|
|
|
14,105
|
|
|
14,105
|
|
Long-term
debt
and other long-term obligations
|
|
|
123,344
|
|
|
130,677
|
|
|
|
|
440,553
|
|
|
441,715
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
63,321
|
|
|
66,576
|
|
Retirement
benefits
|
|
|
47,268
|
|
|
45,967
|
|
Regulatory
liabilities
|
|
|
63,679
|
|
|
58,637
|
|
Other
|
|
|
5,399
|
|
|
6,011
|
|
|
|
|
179,667
|
|
|
177,191
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
705,264
|
|
$
|
815,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral
|
|
part
of these
balance sheets.
|
|
PENNSYLVANIA
POWER COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
6,728
|
|
$
|
53,753
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
6,509
|
|
|
11,351
|
|
Amortization
of regulatory assets
|
|
|
3,411
|
|
|
29,499
|
|
Nuclear
fuel
and other amortization
|
|
|
-
|
|
|
12,912
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(2,809
|
)
|
|
(7,567
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
36,473
|
|
|
15,141
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(51
|
)
|
Prepayments
and other current assets
|
|
|
(3,997
|
)
|
|
(3,186
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(55,497
|
)
|
|
(29,056
|
)
|
Accrued
taxes
|
|
|
(8,003
|
)
|
|
12,108
|
|
Accrued
interest
|
|
|
(802
|
)
|
|
(237
|
)
|
Other
|
|
|
2,012
|
|
|
1,027
|
|
Net
cash
provided from (used for) operating activities
|
|
|
(15,975
|
)
|
|
95,694
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
7,904
|
|
|
22,969
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
(37,750
|
)
|
Long-term
debt
|
|
|
(61,899
|
)
|
|
(849
|
)
|
Dividend
Payments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
(8,000
|
)
|
Preferred
stock
|
|
|
(467
|
)
|
|
(1,534
|
)
|
Net
cash used
for financing activities
|
|
|
(54,462
|
)
|
|
(25,164
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(14,811
|
)
|
|
(69,630
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
-
|
|
|
57,003
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
-
|
|
|
(58,199
|
)
|
Loan
repayments from associated companies
|
|
|
7,172
|
|
|
(14
|
)
|
Cash
investments
|
|
|
78,248
|
|
|
-
|
|
Other
|
|
|
(160
|
)
|
|
296
|
|
Net
cash
provided from (used for) investing activities
|
|
|
70,449
|
|
|
(70,544
|
)
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
12
|
|
|
(14
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
24
|
|
|
38
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
36
|
|
$
|
24
|
|
|
|
|
|
|
|
|
|
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 September 30, 2006, and the related consolidated statement
of
income for each of the three-month and nine-month periods ended September 30,
2006 and 2005 and the consolidated statements of cash flows for the nine-month
periods ended September 30, 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.
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
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, 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.
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 will
affect Penn’s comparative earnings 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 during 2006 (see Outlook -- Regulatory
Matters).
The effects on Penn’s results of operations in the third quarter and nine months
ended September 30, 2006 compared to the same periods of 2005 from the
generation asset transfers are summarized in the following table:
Intra-System
Generation Asset Transfers
|
Income
Statement Effects
|
|
Three
Months
|
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(5)
|
|
|
$
|
(15)
|
|
Nuclear
generated KWH sales
|
(b)
|
|
(42)
|
|
|
|
(118)
|
|
Total
-
Revenues Effect
|
|
|
(47)
|
|
|
|
(133)
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(6)
|
|
|
|
(17)
|
|
Nuclear
operating costs
|
(c)
|
|
(17)
|
|
|
|
(57)
|
|
Provision
for
depreciation
|
(d)
|
|
(1)
|
|
|
|
(4)
|
|
General
taxes
|
(e)
|
|
(1)
|
|
|
|
(1)
|
|
Total
-
Expenses Effect
|
|
|
(25)
|
|
|
|
(79)
|
|
Operating
Income Effect
|
|
|
(22)
|
|
|
|
(54)
|
|
Other
income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
2
|
|
|
|
7
|
|
Capitalized
interest
|
(g)
|
|
(1)
|
|
|
|
(4)
|
|
Total
- Other
Income Effect
|
|
|
1
|
|
|
|
3
|
|
Income
taxes
|
(h)
|
|
(9)
|
|
|
|
(21)
|
|
Net
Income
Effect
|
|
$
|
(12)
|
|
|
$
|
(30)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 allowance for borrowed funds used during construction on nuclear
capital expenditures.
|
(h)
Income tax
effect of the above adjustments.
|
|
|
Results
of Operations
Earnings
on common
stock in the third quarter of 2006 decreased to $3 million from $23 million
in the third quarter of 2005. During the first nine months of 2006 earnings
on
common stock decreased to $6 million from $52 million in the first
nine months of 2005. The lower earnings in both periods of 2006 resulted
principally from the generation asset transfer effects shown in the table above,
lower revenues and higher purchased power costs, partially offset by a reduction
in regulatory asset amortization due to the completion of Penn’s rate
restructuring plan in 2005.
Revenues
Revenues
decreased
by $57 million, or 39%, and $162 million, or 39%, in the third quarter and
the
first nine months of 2006, respectively, as compared with the same periods
of
2005, primarily due to the generation asset transfer impact summarized in the
table above. Excluding the effects of the asset transfer, revenues decreased
by
$10 million, or 7.0% and $29 million, or 7.1%, in the third quarter
and the first nine months of 2006, respectively. These decreases resulted from
lower distribution revenues ($9 million and $26 million, respectively)
primarily reflecting the completion of Penn's generation-related transition
cost
recovery under Penn’s rate restructuring plan and lower wholesale revenues
($6 million and $18 million, respectively) resulting from the
termination of a wholesale sales agreement with a non-affiliate in December
2005. Partially offsetting these decreases were increases in retail generation
revenues of $5 million in the third quarter and $15 million in the
first nine months of 2006, primarily from higher composite unit prices
associated with a 5% rate increase for generation permitted by the PPUC for
all
customer classes.
Distribution
KWH
deliveries were lower to residential customers in the third quarter and to
both
residential and commercial sectors in the first nine months of 2006 due to
the
impact of milder weather conditions compared to the same periods of 2005. Higher
KWH deliveries to industrial customers in both periods of 2006 were largely
due
to increased demand from the steel sector.
Changes
in KWH sales
by customer class in the third quarter and the first nine months of 2006 from
the same periods of 2005 are summarized in the following tables:
Changes
in KWH Sales
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
|
Residential
|
|
|
(1.4)%
|
|
|
(3.6)%
|
|
Commercial
|
|
|
0.8
%
|
|
|
(1.4)%
|
|
Industrial
|
|
|
4.8
%
|
|
|
6.4
%
|
|
Total
Retail Electric Generation Sales
|
|
|
1.4
%
|
|
|
0.5
%
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(1.7)%
|
|
|
(3.8)%
|
|
Commercial
|
|
|
0.8
%
|
|
|
(1.5)%
|
|
Industrial
|
|
|
4.8
%
|
|
|
6.4
%
|
|
Total
Distribution Deliveries
|
|
|
1.3
%
|
|
|
0.4
%
|
|
Expenses
Total
expenses
decreased by $20 million in the third quarter and $71 million in the first
nine
months of 2006 from the same periods of 2005 principally due to the generation
asset transfer impact as shown previously. Excluding the asset transfer effects,
the following table presents changes from the prior year by expense
category:
Expenses
- Changes
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
18
|
|
$
|
40
|
|
Other
operating costs
|
|
|
(3)
|
|
|
(4)
|
|
Provision
for
depreciation
|
|
|
-
|
|
|
(1)
|
|
Amortization
of regulatory assets
|
|
|
(10)
|
|
|
(26)
|
|
General
Taxes
|
|
|
-
|
|
|
(1)
|
|
Net
increase in expenses
|
|
$
|
5
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
Increased
purchased
power costs in the third quarter and the first nine months of 2006, compared
with the same periods of 2005, resulted from higher unit prices associated
with
a new power supply agreement with FES, partially offset by decreases in KWH
purchased due to lower generation sales requirements. Other operating costs
decreased primarily due to lower employee benefit costs.
Amortization
of
regulatory assets was lower in the third quarter and the first nine months
of
2006 as compared to the same periods of 2005 due to the completion of Penn's
rate restructuring plan at the end of 2005.
Other
Income
(Expense)
Miscellaneous
income
increased $3 million in the third quarter and $10 million in the first
nine months of 2006, compared with the same periods of 2005, primarily due
to
the impact of the generation asset transfer. Excluding the effects of the asset
transfer, miscellaneous income was substantially unchanged in the third quarter
and was $3 million higher in the first nine months of 2006, compared with
the same periods of 2005. The increase in the first nine months of 2006 was
primarily due to the absence in 2006 of changes for a $0.7 million civil penalty
payable to the DOJ and a $0.8 million settlement for environmental projects
in
connection with the Sammis New Source Review settlement in the first quarter
of
2005 (see Outlook Environmental Matters).
Net
Interest
Charges
Net
interest charges
increased $1 million in the third quarter and $4 million in the first nine
months of 2006 as compared to the same periods of 2005 primarily due to the
reduction of capitalized interest related to the generation asset transfer.
Excluding the effect of the asset transfer, interest expense decreased by $1
million in the third quarter and was substantially unchanged in the first nine
months of 2006 as compared to the same periods of 2005 due to Penn’s debt
redemptions.
Capital
Resources and Liquidity
Penn’s
cash
requirements for the remainder of 2006 for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met with a
combination of internal cash and short-term credit arrangements. Available
borrowing capacity under credit facilities is used to manage working capital
requirements.
Changes
in Cash
Position
Penn
had $36,000 of
cash and cash equivalents as of September 30, 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 provided
from operating activities in the first nine months of 2006, compared with the
corresponding 2005 period, was as follows:
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
Cash
earnings
(*)
|
|
$
|
14
|
|
$
|
101
|
|
Working
capital and other
|
|
|
(30)
|
|
|
(5)
|
|
Net
cash
provided from operating activities
|
|
$
|
(16)
|
|
$
|
96
|
|
|
|
|
|
|
|
|
|
(*)
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 is a useful financial measure because
it
provides investors and management with an additional means of evaluating its
cash-based operating performance. Generally,
a
non-GAAP financial measure is a numerical measure of a company’s historical or
future financial performance, financial position, or cash flows that either
excludes or includes amounts, or is subject to adjustment that has the effect
of
excluding or including amounts, that are not normally excluded or included
in
the most directly comparable measure calculated and presented in accordance
with
GAAP. In addition, cash earnings (non-GAAP) are not defined under GAAP.
Management believes presenting this non-GAAP measure provides useful information
to investors in assessing Penn’s operating performance from a cash perspective
without the effects of material unusual economic events. Penn’s management
frequently references these non-GAAP financial measures in its decision-making,
using them to facilitate historical and ongoing performance comparisons as
well
as comparisons to the performance of peer companies. These non-GAAP measures
should be considered in addition to, and not as a substitute for, their most
directly comparable financial measures prepared in accordance with
GAAP.
|
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
Net
income
(GAAP)
|
|
|
$
|
7
|
|
$
|
54
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
7
|
|
|
11
|
|
Amortization
of regulatory assets
|
|
|
|
3
|
|
|
29
|
|
Nuclear
fuel
and other amortization
|
|
|
|
-
|
|
|
13
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
|
(3)
|
|
|
(8)
|
|
Other
non-cash
items
|
|
|
|
-
|
|
|
2
|
|
Cash
earnings
(Non-GAAP)
|
|
|
$
|
14
|
|
$
|
101
|
|
|
|
|
|
|
|
|
|
|
The
$87 million
decrease in cash earnings for the first nine months of 2006, as compared to
the
corresponding period of 2005 resulted principally from the generation asset
transfer, as is described above under “Results of Operations”. The
$25 million change in working capital was primarily due to increased cash
outflows from the settlement of accounts payable of $26 million and a
$20 million change in accrued taxes. These variances were partially offset
by an increase in cash of $21 million provided from the collection of
receivables.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities totaled $54 million in the first nine months of 2006,
compared with $25 million in the same period of 2005. The $29 million
increase resulted from $62 million of long-term debt redemptions in 2006
principally related to the generation asset transfer discussed above and a
$15
million decrease in short-term borrowings, partially offset by a $38 million
decrease in preferred stock redemptions and an $8 million decrease in common
stock dividend payments to OE.
As
of September 30,
2006, Penn had $2 million of cash and temporary investments (which included
short-term notes receivable from associated companies) and $21 million of
short-term indebtedness. Penn has authorization from the FERC to incur
short-term debt up to its charter limit of $44 million (including the
utility money pool). Penn had the capability to issue $68 million of
additional FMB on the basis of property additions and retired bonds as of
September 30, 2006. Based upon applicable earnings coverage tests, Penn could
issue up to $136 million of preferred stock (assuming no additional debt
was issued) as of September 30, 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 $25 million under a receivables
financing arrangement which expires on June 28, 2007. The financing arrangements
require payment of an annual facility fee of 0.125% on the entire finance limit.
As a separate legal entity with separate creditors, Penn Funding would have
to
satisfy its separate obligations to creditors before any of its remaining assets
could be made available to Penn.
As
of September 30,
2006, the facility was drawn for $19 million.
On
August 24, 2006,
Penn, FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI as
Borrowers, entered into a new $2.75 billion five-year revolving credit
facility that expires in August 2011, which replaced the prior $2 billion
credit facility. FirstEnergy may request an increase in the total commitments
available under the new facility up to a maximum of $3.25 billion. 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 August 24, 2011
commitment expiration date. Penn's borrowing limit under the facility is
$50 million.
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 the existing credit facility and accounts receivable financing facilities
totaled $56 million as of September 30, 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 September 30, 2006, Penn's debt to total
capitalization as defined under the revolving credit facility was
33%.
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 nine months
of 2006 was 5.09%.
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 the first nine months of 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 $16.8 million at 5.9%;
$12.7 million at 6.15%; $14.25 million at 6%; $10.3 million at
3.61%; and $6.95 million at 5.45%.
Cash
Flows From
Investing Activities
Net
cash provided
from investing activities totaled $70 million in the first nine months of
2006, compared with $71 million of net cash used in the same period of
2005. The $141 million increase in the 2006 period reflects a $55 million
reduction in property additions and $78 million from liquidating investments
(restrictions on short-term investments expired for an escrow fund and a
mortgage indenture deposit), principally as a result of the generation asset
transfer discussed above, and a $7 million increase in loan repayments from
associated companies.
During
the last
quarter of 2006, capital requirements for property additions are expected to
be
approximately $4 million. Penn has sinking fund requirements of
approximately $0.5 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 approximately
$91 million of which approximately $19 million applies to 2006. Penn
had no other material obligations as of September 30, 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 as of
September 30, 2006 and $59 million as of December 31, 2005, and are
included under Noncurrent Liabilities on the Consolidated Balance Sheets.
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 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 before the PPUC 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. On April 20, 2006, the PPUC approved the
Recommended Decision with additional modifications to use an RFP process with
two separate solicitations. An initial solicitation was held for Penn in May
2006 with all tranches fully subscribed, which was approved by the PPUC on
June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
Penn. The tranches for the Residential Group and Small Commercial Group were
fully subscribed. However, supply was not acquired for two tranches for the
Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
for
the second bid. A contingency solicitation was held on August 15, 2006 for
the two remaining Large Commercial Group tranches. The PPUC rejected the bids
from the contingency solicitation and directed Penn’s independent auction
manager to offer the two unfilled Large Commercial tranches to the companies
which had won tranches in the prior solicitations. This resulted in the
acquisition of a supplier for the two remaining tranches, which were filed
and
accepted by the PPUC in a secretarial letter that was entered on
September 22, 2006. On August 24, 2006, Penn made a compliance filing.
OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
exceptions on September 5, 2006. On September 21, 2006, Penn submitted
a revised compliance filing to the PPUC for the Residential Group and Small
Commercial Group as a result of an agreement between Penn, OCA and OSBA. The
PPUC approved proposed rates for the large commercial and industrial customers
at the PPUC Public meeting on October 19, 2006, and found that the results
of the competitive solicitation process were consistent with prevailing market
prices.
On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
April 28, 2006 and May 4, 2006, which together decided the issues
associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
impose a geographic limitation on the sources of alternative energy credits.
On
June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
ruling on the method by which alternative energy credits may be acquired and
traded. Penn is unable to predict the outcome of this appeal.
On
December 29,
2005, the FERC issued an order setting the two power sales agreements for
hearing. The order criticized the Ohio CBP, 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. Under the procedural
schedule approved in this case, FES expected an initial decision to be issued
in
late January 2007. However, on July 14, 2006, the Chief Judge granted the
joint
motion of FES and the Trial Staff to appoint a settlement judge in this
proceeding and the procedural schedule was suspended pending settlement
discussions among the parties. A settlement conference was held on September
5,
2006. FES and the Ohio Companies, Penn, and the PUCO, along
with other
parties, reached an agreement to settle the case. The settlement was filed
with
the FERC on October 17, 2006, and was unopposed by the remaining parties,
including the FERC Trial Staff. Initial comments to the settlement are due
by
November 6, 2006.
The
terms of the
settlement provide for modification of both the Ohio and Penn power supply
agreements with FES. The wholesale rate charged by FES under the Penn power
supply agreement will be no greater than the generation component of charges for
retail PLR load in Pennsylvania. The FERC is expected to act on this case
by the
end of the fourth quarter of 2006.
As
a result of Penn’s
PLR competitive solicitation process approved by the PPUC, FES was selected
as
the winning bidder for a number of the tranches for individual customer classes.
The balance of the tranches will be supplied by unaffiliated power suppliers.
On
October 2, 2006, FES filed an application with FERC under Section 205 of
the
Federal Power Act for authorization to make these affiliate sales to Penn.
Interventions or protests were due on this filing on October 23, 2006. Penn
was
the only party to file an intervention in this proceeding. The FERC
is expected
to act on this filing on or before December 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 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 ($400 million of which is expected to be spent in 2007 with
the
primary portion of the remaining $1.1 billion expected to be spent in 2008
and
2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power
Corporation under which Bechtel will engineer, procure, and construct air
quality control systems for the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement
with
B&W. The above requirements will be the responsibility of FGCO.
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.
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 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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
County Common Pleas Court seeking reimbursement for claims paid to numerous
insureds who allegedly suffered losses as a result of the August 14, 2003
outages. All of the insureds appear to be non-customers. The plaintiff insurance
companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
the Ohio Companies and Penn were served on October 27, 2006, and expect to
seek summary dismissal of these cases. No estimate of potential liability is
available for any of these cases.
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.
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
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements”
In September 2006, the SEC issued SAB 108, which provides interpretive guidance
on how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments
will
need to be reconsidered using both the rollover and iron curtain methods.
This
guidance will be effective for Penn in the fourth quarter of 2006. Penn
does
not expect this Statement to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
Penn is currently evaluating the impact of this Statement on its financial
statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for Penn as of December 31, 2006. Penn is currently
evaluating the impact of this Statement on its financial statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
In June 2006, the FASB issued FIN 48 which clarifies the accounting for
uncertainty in income taxes recognized in an enterprise’s financial statements
in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This
interpretation prescribes a recognition threshold and measurement attribute
for
the financial statement recognition and measurement of a tax position taken
or
expected to be taken on a tax return. This interpretation also provides guidance
on derecognition, classification, interest, penalties, accounting in interim
periods, disclosure and transition. The evaluation of a tax position in
accordance with this interpretation will be a two-step process. The first
step
will determine if it is more likely than not that a tax position will be
sustained upon examination and should therefore be recognized. The second
step
will measure a tax position that meets the more likely than not recognition
threshold to determine the amount of benefit to recognize in the financial
statements. This interpretation is effective for fiscal years beginning after
December 15, 2006. Penn is currently evaluating the impact of this
Statement.
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
Restated
|
|
|
|
Restated
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF INCOME
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
|
$
|
911,068
|
|
$
|
900,247
|
|
$
|
2,098,344
|
|
$
|
2,024,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
|
546,125
|
|
|
517,213
|
|
|
1,204,880
|
|
|
1,115,738
|
|
Other
operating costs
|
|
|
|
90,578
|
|
|
112,690
|
|
|
245,711
|
|
|
293,996
|
|
Provision
for
depreciation
|
|
|
|
21,099
|
|
|
19,659
|
|
|
62,553
|
|
|
59,721
|
|
Amortization
of regulatory assets
|
|
|
|
78,052
|
|
|
85,485
|
|
|
210,323
|
|
|
224,109
|
|
Deferral
of
new regulatory assets
|
|
|
|
-
|
|
|
(1,097
|
)
|
|
-
|
|
|
(28,862
|
)
|
General
taxes
|
|
|
|
19,187
|
|
|
19,538
|
|
|
49,691
|
|
|
49,802
|
|
Total
expenses
|
|
|
|
755,041
|
|
|
753,488
|
|
|
1,773,158
|
|
|
1,714,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
|
156,027
|
|
|
146,759
|
|
|
325,186
|
|
|
310,126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
|
2,091
|
|
|
4,777
|
|
|
8,162
|
|
|
5,264
|
|
Interest
expense
|
|
|
|
(21,437
|
)
|
|
(19,960
|
)
|
|
(62,420
|
)
|
|
(60,963
|
)
|
Capitalized
interest
|
|
|
|
1,004
|
|
|
497
|
|
|
2,933
|
|
|
1,337
|
|
Total
other
expense
|
|
|
|
(18,342
|
)
|
|
(14,686
|
)
|
|
(51,325
|
)
|
|
(54,362
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
|
137,685
|
|
|
132,073
|
|
|
273,861
|
|
|
255,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
|
58,316
|
|
|
58,197
|
|
|
120,506
|
|
|
114,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
|
79,369
|
|
|
73,876
|
|
|
153,355
|
|
|
141,628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
|
917
|
|
|
125
|
|
|
1,167
|
|
|
375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
|
$
|
78,452
|
|
$
|
73,751
|
|
$
|
152,188
|
|
$
|
141,253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
$
|
79,369
|
|
$
|
73,876
|
|
$
|
153,355
|
|
$
|
141,628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
|
100
|
|
|
103
|
|
|
207
|
|
|
208
|
|
Income
tax
expense related to other comprehensive income
|
|
|
|
41
|
|
|
42
|
|
|
84
|
|
|
85
|
|
Other
comprehensive income, net of tax
|
|
|
|
59
|
|
|
61
|
|
|
123
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
$
|
79,428
|
|
$
|
73,937
|
|
$
|
153,478
|
|
$
|
141,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Jersey
Central Power & Light Company are an integral part of these
statements.
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
September
30,
|
|
December
31,
|
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
|
$
|
58
|
|
$
|
102
|
|
Receivables-
|
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,066,000 and $3,830,000,
|
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
|
|
310,347
|
|
|
258,077
|
|
Associated
companies
|
|
|
|
|
161
|
|
|
203
|
|
Other
(less
accumulated provisions of $216,000 and $204,000,
|
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
|
|
39,565
|
|
|
41,456
|
|
Notes
receivable - associated companies
|
|
|
|
|
27,056
|
|
|
18,419
|
|
Materials
and
supplies, at average cost
|
|
|
|
|
2,017
|
|
|
2,104
|
|
Prepaid
taxes
|
|
|
|
|
40,060
|
|
|
10,137
|
|
Other
|
|
|
|
|
9,045
|
|
|
6,928
|
|
|
|
|
|
|
428,309
|
|
|
337,426
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
|
|
4,008,742
|
|
|
3,902,684
|
|
Less
-
Accumulated provision for depreciation
|
|
|
|
|
1,467,604
|
|
|
1,445,718
|
|
|
|
|
|
|
2,541,138
|
|
|
2,456,966
|
|
Construction
work in progress
|
|
|
|
|
77,450
|
|
|
98,720
|
|
|
|
|
|
|
2,618,588
|
|
|
2,555,686
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
Nuclear
fuel
disposal trust
|
|
|
|
|
168,375
|
|
|
164,203
|
|
Nuclear
plant
decommissioning trusts
|
|
|
|
|
156,205
|
|
|
145,975
|
|
Other
|
|
|
|
|
2,080
|
|
|
2,580
|
|
|
|
|
|
|
326,660
|
|
|
312,758
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
|
|
2,178,460
|
|
|
2,226,591
|
|
Goodwill
|
|
|
|
|
1,977,551
|
|
|
1,985,858
|
|
Prepaid
pension costs
|
|
|
|
|
152,113
|
|
|
148,054
|
|
Other
|
|
|
|
|
17,587
|
|
|
17,733
|
|
|
|
|
|
|
4,325,711
|
|
|
4,378,236
|
|
|
|
|
|
$
|
7,699,268
|
|
$
|
7,584,106
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
|
$
|
70,140
|
|
$
|
207,231
|
|
Notes
payable-
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
|
|
137,184
|
|
|
181,346
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
|
|
9,754
|
|
|
37,955
|
|
Other
|
|
|
|
|
169,570
|
|
|
149,501
|
|
Accrued
taxes
|
|
|
|
|
37,365
|
|
|
54,356
|
|
Accrued
interest
|
|
|
|
|
36,212
|
|
|
19,916
|
|
Cash
collateral from suppliers
|
|
|
|
|
48,582
|
|
|
141,225
|
|
Other
|
|
|
|
|
65,148
|
|
|
86,884
|
|
|
|
|
|
|
573,955
|
|
|
878,414
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
|
Common
stock,
$10 par value, authorized 16,000,000 shares-
|
|
|
|
|
|
|
|
|
|
15,371,270
shares outstanding
|
|
|
|
|
153,713
|
|
|
153,713
|
|
Other
paid-in
capital
|
|
|
|
|
2,995,029
|
|
|
3,003,190
|
|
Accumulated
other comprehensive loss
|
|
|
|
|
(1,907
|
)
|
|
(2,030
|
)
|
Retained
earnings
|
|
|
|
|
163,079
|
|
|
55,890
|
|
Total
common
stockholder's equity
|
|
|
|
|
3,309,914
|
|
|
3,210,763
|
|
Preferred
stock
|
|
|
|
|
-
|
|
|
12,649
|
|
Long-term
debt
and other long-term obligations
|
|
|
|
|
1,327,809
|
|
|
972,061
|
|
|
|
|
|
|
4,637,723
|
|
|
4,195,473
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
|
|
1,205,064
|
|
|
1,237,249
|
|
Accumulated
deferred income taxes
|
|
|
|
|
814,236
|
|
|
812,034
|
|
Nuclear
fuel
disposal costs
|
|
|
|
|
181,317
|
|
|
175,156
|
|
Asset
retirement obligations
|
|
|
|
|
83,188
|
|
|
79,527
|
|
Retirement
benefits
|
|
|
|
|
71,785
|
|
|
72,454
|
|
Other
|
|
|
|
|
132,000
|
|
|
133,799
|
|
|
|
|
|
|
2,487,590
|
|
|
2,510,219
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,699,268
|
|
$
|
7,584,106
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Jersey
Central Power & Light Company are an integral part of these balance
sheets.
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
Restated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
153,355
|
|
$
|
141,628
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
62,553
|
|
|
59,721
|
|
Amortization
of regulatory assets
|
|
|
210,323
|
|
|
224,109
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
(28,862
|
)
|
Deferred
purchased power and other costs
|
|
|
(213,621
|
)
|
|
(168,646
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
25,217
|
|
|
5,204
|
|
Accrued
compensation and retirement benefits
|
|
|
(4,196
|
)
|
|
(6,545
|
)
|
Cash
collateral from (returned to) suppliers
|
|
|
(108,926
|
)
|
|
76,674
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
(50,337
|
)
|
|
(25,626
|
)
|
Materials
and
supplies
|
|
|
86
|
|
|
572
|
|
Prepaid
taxes
|
|
|
(29,923
|
)
|
|
1,264
|
|
Other
current
assets
|
|
|
(2,118
|
)
|
|
(3,028
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(8,131
|
)
|
|
26,214
|
|
Accrued
taxes
|
|
|
(16,992
|
)
|
|
77,341
|
|
Accrued
interest
|
|
|
16,296
|
|
|
14,931
|
|
Other
|
|
|
(15,130
|
)
|
|
25,814
|
|
Net
cash
provided from operating activities
|
|
|
18,456
|
|
|
420,765
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
382,400
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(162,157
|
)
|
|
(67,648
|
)
|
Short-term
borrowings, net
|
|
|
(44,162
|
)
|
|
(133,600
|
)
|
Preferred
stock
|
|
|
(13,461
|
)
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(45,000
|
)
|
|
(83,000
|
)
|
Preferred
stock
|
|
|
(354
|
)
|
|
(375
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
117,266
|
|
|
(284,623
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(123,540
|
)
|
|
(133,498
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(8,638
|
)
|
|
685
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
138,936
|
|
|
103,360
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(141,107
|
)
|
|
(105,531
|
)
|
Other
|
|
|
(1,417
|
)
|
|
(749
|
)
|
Net
cash used
for investing activities
|
|
|
(135,766
|
)
|
|
(135,733
|
)
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(44
|
)
|
|
409
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
102
|
|
|
162
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
58
|
|
$
|
571
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Jersey
Central Power & Light Company are an integral part of these
statements.
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of Jersey
Central Power & Light Company:
We
have reviewed the
accompanying consolidated balance sheet of Jersey Central Power & Light
Company and its subsidiaries as of September 30, 2006, and the related
consolidated statements of income and comprehensive income for each of the
three-month and nine-month periods ended September 30, 2006 and 2005 and the
consolidated statements of cash flows for the nine-month periods ended September
30, 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.
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 restatement of its previously issued consolidated financial
statements for the years ended December 31, 2004 and 2003 as discussed in Note
2(I) 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
October
31,
2006
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS
OF
RESULTS
OF
OPERATIONS AND
FINANCIAL CONDITION
JCP&L
is a
wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
business in New Jersey, providing regulated electric transmission and
distribution services. JCP&L also provides generation services to those
customers electing to retain JCP&L as their power supplier.
Restatements
As
further discussed in Note 15 to the Consolidated Financial Statements, JCP&L
restated its consolidated financial statements for the three months and nine
months ended September 30, 2005. The revisions are the result of a tax
audit from the State of New Jersey, in which JCP&L became aware that the New
Jersey Transitional Energy Facilities Assessment is not an allowable deduction
for state income tax purposes.
Results
of Operations
Earnings
on common
stock in the third quarter of 2006 increased to $78 million from
$74 million in 2005. The increase was principally due to higher revenues,
decreased other operating costs and lower amortization of regulatory assets,
partially offset by increased purchased power costs. In the first nine months
of
2006, earnings on common stock increased to $152 million compared to
$141 million for the same period in 2005. The increase was primarily due to
higher revenues, lower other operating costs and reduced amortization of
regulatory assets, partially offset by increased purchased power costs and
the
absence of the new regulatory asset recognized in 2005.
Revenues
Revenues
increased
$11 million or 1.2% in the third quarter of 2006 and $74 million or
3.6% for the first nine months of 2006 compared with the same periods of 2005.
The higher revenues in both periods were primarily due to retail generation
revenue increases ($49 million and $115 million in the third quarter and the
first nine months of 2006, respectively), partially offset by decreases in
wholesale revenue ($22 million in the third quarter and $28 million in the
first nine months of 2006). Distribution revenues declined $20 million in
the third quarter and $15 million in the first nine months of 2006 compared
to the same periods of the prior year.
The
retail
generation revenue increases in both the third quarter and the first nine months
of 2006, as compared to the previous year, were due to higher unit prices
resulting from the BGS auction effective in May 2006, which offset declines
in
retail generation KWH sales. Revenue from residential customers increased
$20 million and $48 million in the third quarter and the first nine
months of 2006, respectively, as compared to the same periods in 2005.
Generation revenue from commercial customers also increased for the same periods
by $26 million and $63 million, respectively. The milder weather in
the third quarter (cooling degree days were 18.6% below the previous year)
and
in the first nine months of 2006 (heating degree days were 17.7% below and
cooling degree days were 15.3% below the previous year) resulted in lower KWH
sales to residential customers in the third quarter and the first nine months
of
2006. KWH sales to commercial customers increased 0.4% in the third quarter
and
2.1% for the first nine months of 2006 as an increase in the number of
commercial customers more than offset the impact of milder weather. Revenues
from industrial customers increased $2 million in the third quarter of 2006
as a result of higher unit prices and KWH sales. The industrial sector revenue
increase of $4 million in the first nine months of 2006 also reflected higher
unit prices but were partially offset by lower sales compared to the prior
year
period. Wholesale sales revenues decreased $22 million in the third quarter
and $28 million for the first nine months of 2006 as compared to 2005 due
to lower unit prices.
The
decrease in
distribution revenues in the third quarter of 2006 resulted from lower KWH
throughput and the impact of the new securitization (see “Regulatory Matters”
further below) which reduced distribution revenues and increased other revenues.
Distribution KWH deliveries declined for the first nine months of 2006 as
compared to the previous year which decreased revenues by $15 million. The
distribution revenue reduction was primarily due to lower KWH throughput
partially offset by higher prices resulting from a distribution rate increase
pursuant to the stipulated settlements approved by the NJBPU on May 25, 2005.
Other revenues increased $4 million and $2 million in the third
quarter and in the first nine months of 2006, respectively, as compared to
the
comparable periods in 2005 due to the new transition bond charge
revenue.
Changes
in KWH sales
by customer class in the third quarter and the first nine months of 2006
compared to the same periods of 2005 are summarized in the following
table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
(3.6
|
)%
|
|
(2.3
|
)%
|
Wholesale
|
|
|
(0.4
|
)%
|
|
0.6
|
%
|
Total
Electric Generation Sales
|
|
|
(3.0
|
)%
|
|
(1.7
|
)%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(6.6
|
)%
|
|
(5.5
|
)%
|
Commercial
|
|
|
1.4
|
%
|
|
0.1
|
%
|
Industrial
|
|
|
(8.8
|
)%
|
|
(7.5
|
)%
|
Total
Distribution Deliveries
|
|
|
(3.7
|
)%
|
|
(3.5
|
)%
|
|
|
|
|
|
|
|
|
Expenses
Total
operating
expenses increased by $2 million in the third quarter and $59 million in the
first nine months of 2006 as compared to the same periods of the prior year.
The
following table presents changes from the prior year by expense
category:
|
|
Three
|
|
Nine
|
|
Expenses
- Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
29
|
|
$
|
89
|
|
Other
operating costs
|
|
|
(22
|
)
|
|
(48
|
)
|
Provision
for
depreciation
|
|
|
1
|
|
|
3
|
|
Amortization
of regulatory assets
|
|
|
(7
|
)
|
|
(14
|
)
|
Deferral
of
new regulatory assets
|
|
|
1
|
|
|
29
|
|
Net
increase in expenses
|
|
$
|
2
|
|
$
|
59
|
|
|
|
|
|
|
|
|
|
The
increases in
purchased power costs reflected higher unit prices resulting from the 2006
BGS
auction. Other operating costs in the third quarter of 2005
included the
affect of an arbitration decision in connection with a JCP&L bargaining
union grievance challenging JCP&L's call out procedure. As a result of the
arbitration decision, JCP&L reserved $16 million in the third quarter of
2005. Other operating costs were also higher in both periods of 2005 due to
an
extensive effort to improve system reliability as well as impacts from a labor
union strike that ended on March 15, 2005. Amortization of regulatory assets
decreased $7 million in the third quarter and $14 million in the first
nine months of 2006 compared to the same periods in 2005 due to a reduction
in
the level of MTC revenue recovery. The changes in the deferral of new regulatory
assets reflect the NJBPU’s 2005 approval for JCP&L to defer accelerated tree
trimming and other reliability costs that were incurred in 2003 and
2004.
Miscellaneous
income
decreased $3 million in the third quarter of 2006, but increased $3 million
for
the first nine months compared to the same periods in 2005. The decrease in
the
third quarter of 2006 was due to the absence in 2006 of a gain from the sale
of
property in 2005, while the increase for the first nine months of 2006 was
attributable to income received from customer requested service projects.
Capital
Resources and Liquidity
JCP&L’s
cash
requirements for the remainder of 2006 for expenses, construction expenditures
and scheduled debt maturities are expected to be met with cash from operations.
Changes
in Cash
Position
As
of
September 30, 2006, JCP&L had $58,000 of cash and cash equivalents
compared with $102,000 as of December 31, 2005. The major sources for
changes in these balances are summarized below.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities in the first nine months of 2006 and 2005 were as follows:
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
millions)
|
|
|
Cash
earnings
(1)
|
|
$
|
234
|
|
$
|
227
|
|
|
Working
capital and other
|
|
|
(216
|
)
|
|
194
|
|
|
Net
cash
provided from operating activities
|
|
$
|
18
|
|
$
|
421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. JCP&L believes that cash earnings is a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. Generally, a non-GAAP financial
measure is a numerical measure of a company’s historical or future financial
performance, financial position, or cash flows that either excludes or includes
amounts, or is subject to adjustment that has the effect of excluding or
including amounts, that are not normally excluded or included in the most
directly comparable measure calculated and presented in accordance with GAAP.
In
addition, cash earnings (non-GAAP) are not defined under GAAP. Management
believes presenting this non-GAAP measure provides useful information to
investors in assessing JCP&L’s operating performance from a cash perspective
without the effects of material unusual economic events. JCP&L’s management
frequently references these non-GAAP financial measures in its decision-making,
using them to facilitate historical and ongoing performance comparisons as
well
as comparisons to the performance of peer companies. These non-GAAP measures
should be considered in addition to, and not as a substitute for, their most
directly comparable financial measures prepared in accordance with
GAAP.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
153
|
|
$
|
142
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
63
|
|
|
60
|
|
Amortization
of regulatory assets
|
|
|
210
|
|
|
224
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
(29
|
)
|
Deferred
purchased power and other costs
|
|
|
(214
|
)
|
|
(169
|
)
|
Deferred
income taxes
|
|
|
26
|
|
|
6
|
|
Other
non-cash
items
|
|
|
(4
|
)
|
|
(7
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
234
|
|
$
|
227
|
|
|
|
|
|
|
|
|
|
The
$7 million
increase in cash earnings is described under “Results of Operations.” The
$410 million change in working capital primarily resulted from a
$186 million change in cash collateral returned to suppliers, changes in
accrued taxes of $94 million, payables of $34 million, prepaid taxes of $30
million, receivables of $25 million, and the 2005 arbitration decision of
$16 million. In the year 2005, JCP&L received cash collateral payments from
its suppliers of $135 million. During the first nine months of 2006, JCP&L
returned $109 million back to its suppliers.
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities was $117 million in the first nine months of 2006
as
compared to net cash used of $285 million in same period of 2005. The
change resulted from a $382 million issuance of long-term debt, a $90 million
decrease in short-term debt redemptions and a $38 million reduction in
common stock dividend payments to FirstEnergy, partially offset by
$108 million of additional debt and preferred stock redemptions in the
first nine months of 2006.
JCP&L had
$27 million
of cash and temporary investments (which includes short-term notes receivable
from associated companies) and approximately $137 million of short-term
indebtedness as of September 30, 2006. JCP&L has authorization from the
FERC to incur short-term debt up to its charter limit of $429 million
(including the utility money pool). JCP&L will not issue FMB other than as
collateral for senior notes, since its senior note indenture prohibits (subject
to certain exceptions) JCP&L from issuing any debt which is senior to the
senior notes. As of September 30, 2006, JCP&L had the capability to
issue $626 million of additional senior notes based upon FMB collateral. As
of September 30, 2006, based upon applicable earnings coverage tests and
its charter, JCP&L could issue $1.3 billion of preferred stock
(assuming no additional debt was issued).
JCP&L
has the
ability to borrow from FirstEnergy and its regulated affiliates 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 agreement must repay the principal,
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 nine months of 2006 was 5.09%.
On
August 24, 2006,
JCP&L, FirstEnergy, OE, Penn, CEI, TE, Penelec, Met-Ed, FES and ATSI, as
Borrowers, entered into a new $2.75 billion five-year revolving credit facility,
which replaced the prior $2 billion credit facility. FirstEnergy may
request an increase in the total commitments available under the new facility
up
to a maximum of $3.25 billion. Commitments
under
the new facility are available until August 24, 2011, unless the lenders
agree, at the request of the Borrowers, to two additional one-year extensions.
Generally, borrowings under the facility must be repaid within 364 days.
Available amounts for each Borrower are subject to a specified sub-limit, as
well as applicable regulatory and other limitations. JCP&L's
borrowing limit under the facility is $425 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.
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
September 30, 2006, JCP&L's debt to total capitalization as defined
under the revolving credit facility was 23%.
The
facility does
not contain any provisions that either restrict JCP&L'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 its credit ratings.
JCP&L's
access
to the capital markets and the costs of financing are dependent on the ratings
of its securities and that of FirstEnergy. As of September 30, 2006,
JCP&L's and FirstEnergy’s ratings outlook from S&P on all securities was
stable. The ratings outlook from Moody’s and Fitch on all securities is
positive.
On June 8, 2006, the NJBPU approved JCP&L’s request to issue
securitization bonds associated with BGS stranded cost deferrals. On
August 10, 2006, JCP&L Transition Funding II, a wholly owned subsidiary
of JCP&L, issued $182 million of transition bonds with a weighted
average interest rate of 5.5%. As required by the Electric Discount and Energy
Competition Act of 1999, as amended, JCP&L used the proceeds principally to
reduce stranded costs, including basic generation transition costs, through
the
retirement of debt, including short-term debt, or equity or both, and also
to
pay related expenses.
On
May 12,
2006, JCP&L issued $200 million of 6.40% secured Senior Notes due 2036.
The proceeds of the offering were used to repay at maturity $150 million
aggregate principal amount of JCP&L’s 6.45% Senior Notes due May 15,
2006 and for general corporate purposes.
Cash
Flows From
Investing Activities
Net
cash used for
investing activities was $136 million in the first nine months of 2006,
unchanged from the previous year. The $10 million reduction in property
additions was completely offset by $10 million of loans to associated
companies.
During
the last
quarter
of 2006, capital requirements for property additions and improvements are
expected to be about $36 million. These cash requirements are expected to
be satisfied from cash from operations.
JCP&L’s
capital
spending for the period 2006-2010 is expected to be approximately
$909 million for property additions, of which approximately
$159 million applies to 2006.
Market
Risk Information
JCP&L
uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price fluctuations. FirstEnergy’s Risk Policy
Committee, comprised of members of senior management, provides general oversight
to risk management activities.
Commodity
Price
Risk
JCP&L is exposed to market risk primarily due to fluctuations in
electricity, energy transmission and natural gas prices. To manage the
volatility relating to these exposures, JCP&L 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 JCP&L’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 the power purchase
agreements with NUG entities that were structured pursuant to the Public Utility
Regulatory Policies Act of 1978. These non-trading contracts had been adjusted
to fair value at the end of each quarter, with a corresponding regulatory asset
recognized for above-market costs. The changes in the fair value of commodity
derivative contracts related to energy production during the third quarter
and
first nine months of 2006 are summarized in the following table:
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
September
30, 2006
|
|
September
30, 2006
|
|
of
Commodity Derivative Contracts
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
(In
millions)
|
|
Change
in the Fair Value of
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net liability at beginning of period
|
$
|
(1,111
|
)
|
$
|
-
|
|
$
|
(1,111
|
)
|
$
|
(1,223
|
)
|
$
|
-
|
|
$
|
(1,223
|
)
|
Additions/change
in value of existing contracts
|
|
(164
|
)
|
|
-
|
|
|
(164
|
)
|
|
(193
|
)
|
|
-
|
|
|
(193
|
)
|
Settled
contracts
|
|
81
|
|
|
-
|
|
|
81
|
|
|
222
|
|
|
-
|
|
|
222
|
|
Net
Liabilities - Derivative Contracts
at
End
of Period (1)
|
$
|
(1,194
|
)
|
$
|
-
|
|
$
|
(1,194
|
)
|
$
|
(1,194
|
)
|
$
|
-
|
|
$
|
(1,194
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
(2
|
)
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
(1
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
assets (net)
|
$
|
81
|
|
$
|
-
|
|
$
|
81
|
|
$
|
(30
|
)
|
$
|
-
|
|
$
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) These
represent NUG
contracts that are offset by a regulatory asset.
(2) 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
September 30, 2006 as follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
$
|
11
|
|
$
|
-
|
|
$
|
11
|
|
Other
noncurrent liabilities
|
|
|
(1,205
|
)
|
|
-
|
|
|
(1,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
liabilities
|
|
$
|
(1,194
|
)
|
$
|
-
|
|
$
|
(1,194
|
)
|
The
valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, JCP&L relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. JCP&L uses these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of commodity derivative
contracts as of September 30, 2006 are summarized by year in the following
table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
2006(1)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Other
external
sources (2)
|
|
$
|
(66
|
)
|
$
|
(269
|
)
|
$
|
(248
|
)
|
$
|
(197
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
(780
|
)
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(181
|
)
|
|
(233
|
)
|
|
(414
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
(66
|
)
|
$
|
(269
|
)
|
$
|
(248
|
)
|
$
|
(197
|
)
|
$
|
(181
|
)
|
$
|
(233
|
)
|
$
|
(1,194
|
)
|
(1) For
the last quarter
of 2006.
(2) Broker
quote
sheets.
(3) These
represent NUG
contracts that are offset by a regulatory asset .
JCP&L performs sensitivity analyses to estimate its exposure to the market
risk of its commodity positions. A hypothetical 10% adverse shift in quoted
market prices in the near term on both its trading and non-trading derivative
instruments would not have had a material effect on JCP&L’s consolidated
financial position or cash flows as of September 30, 2006. JCP&L estimates
that if energy commodity prices experienced an adverse 10% change, net income
for the next twelve months would not change, as the prices for all commodity
positions are already above the contract price caps.
Equity
Price
Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their current
fair value of approximately $91 million and $84 million as of
September 30, 2006 and December 31, 2005, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a
$9 million reduction in fair value as of September 30, 2006.
Regulatory
Matters
Regulatory assets are costs which have been authorized by the NJBPU 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
of JCP&L’s regulatory assets are expected to continue to be recovered under
the provisions of the regulatory proceedings discussed below. JCP&L’s
regulatory assets totaled $2.2 billion as of September 30, 2006 and
December 31, 2005.
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 September 30, 2006, the
accumulated deferred cost balance totaled approximately $340 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
bonds associated with BGS stranded cost deferrals. On August 10, 2006,
JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued
$182 million of transition bonds with a weighted average interest rate of 5.5%.
On
December 2, 2005, JCP&L filed its 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 23, 2006, JCP&L filed updated data
reflecting actual amounts through December 31, 2005 of $154 million of
costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing
conference was held with the presiding ALJ. On July 18, 2006, JCP&L
filed rebuttal testimony that included a request for an additional
$14 million of costs that had been eliminated from the securitized amount.
Evidentiary hearings were held during September 2006 and the briefing schedule
has been postponed pending settlement discussions.
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 latest quarterly reliability reports were submitted on
September 12, 2006. As of September 30, 2006, there were no
performance penalties issued by the NJBPU.
Reacting 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. On June 21, 2006,
the NJBPU approved the continued use of a descending block auction for the
Fixed
Price Residential Class. JCP&L filed its 2007 BGS company specific addendum
on July 10, 2006. On October 27, 2006, the NJBPU approved the auction
format to procure the 2007 Commercial Industrial Energy Price as well as the
specific rules for both the Fixed Price and Commercial Industrial Energy Price
auctions. These rules were essentially unchanged from the prior
auctions.
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 the Ratepayer Advocate’s comments. A schedule for
further NJBPU 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 repeal
of
PUHCA pursuant to 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 on February 7, 2006 and comments were submitted
to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with
an effective date of October 2, 2006. These regulations are not expected
to
materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the
NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing
various issues including access to books and records, ring-fencing, cross
subsidization, corporate governance and related matters. With the approval
of
the NJBPU Staff, the affected utilities jointly submitted an alternative
proposal on June 1, 2006. Comments on the alternative proposal were submitted
on
June 15, 2006.
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. JCP&L filed a request with the IRS for a ruling on the issue. JCP&L
was advised by the IRS on April 10, 2006 that the ruling was tentatively
adverse. On April 28, 2006, the NJBPU directed JCP&L to withdraw its
request for a private letter ruling on this issue, which had been previously
filed with the IRS as ordered by the NJBPU. On May 11, 2006, after a JCP&L
Motion for Reconsideration was denied by the NJBPU, JCP&L filed to withdraw
the request for a private letter ruling. On July 19, 2006, the IRS acknowledged
that the JCP&L ruling request was withdrawn.
On
November 18,
2004, the FERC issued an order eliminating the RTOR for transmission service
between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
transmission owners within MISO and PJM to submit compliance filings containing
a SECA mechanism 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 was held in May 2006. Initial briefs were submitted
on
June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding Judge
issued an Initial Decision on August 10, 2006, rejecting the compliance filings
made by the RTOs and transmission owners, ruling on various issues and directing
new compliance filings. This decision is subject to review and approval by
the
FERC. Briefs addressing the Initial Decision were filed on September 11, 2006
and October 20, 2006. A final order could be issued by the FERC by the end
of
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 refund 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. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
the cost of all PJM transmission facilities should be recovered through a
postage stamp rate. The
ALJ recommended
an April 1, 2006 effective date for this change in rate design. If the FERC
accepts this recommendation, the transmission rate applicable to many load
zones
in PJM would increase. FirstEnergy believes that significant additional
transmission revenues would have to be recovered from the JCP&L, Met-Ed and
Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
on August 14, 2006 and September 5, 2006. The case will be reviewed by the
FERC
with a decision anticipated in the fourth quarter of 2006.
See Note 11 to the consolidated financial statements for further details
and a complete discussion of regulatory matters in New Jersey.
Environmental
Matters
JCP&L accrues environmental liabilities when it concludes that it is
probable that it has an obligation for such costs and can reasonably determine
the amount of such costs. Unasserted claims are reflected in JCP&L’s
determination of environmental liabilities and are accrued in the period that
they are both probable and reasonably estimable.
JCP&L has been named as a PRP at waste disposal sites which may require
cleanup under the Comprehensive Environmental Responsive, Comprehension 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 PRPs for a particular
site are held liable on a joint and several basis. Therefore, environmental
liabilities that are considered probable have been recognized on the
Consolidated Balance Sheet as of September 30, 2006, based on estimates of
the total costs of cleanup, JCP&L’s 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
$55 million have been accrued through September 30, 2006.
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 JCP&L's normal business operations pending against
JCP&L. The other material items not otherwise discussed below are described
in Note 10(C) to the consolidated financial statements.
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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
FirstEnergy was also named, along with several other entities, in a complaint
in
New Jersey State Court. The allegations against FirstEnergy were based, in
part,
on an alleged failure to protect the citizens of Jersey City from an electrical
power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City.
A responsive pleading has been filed. On April 28, 2006, the Court granted
FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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.
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 arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss as premature
a
JCP&L appeal of the award filed on October 18, 2005. JCP&L intends
to re-file an 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 other material items not otherwise discussed above are described in
Note 10(C) to the consolidated financial statements.
New
Accounting Standards and Interpretations
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements”
In September 2006, the SEC issued SAB 108, which provides interpretive guidance
on how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments will
need to be reconsidered using both the rollover and iron curtain methods. This
guidance will be effective for JCP&L in the fourth quarter of 2006.
JCP&L does
not expect this
Statement to have a material impact on its financial statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157, that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
JCP&L is currently evaluating the impact of this Statement on its financial
statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for JCP&L as of December 31, 2006. JCP&L
is
currently evaluating the impact of this Statement on its financial
statements.
|
FSP
FIN
46(R)-6 - “Determining the Variability to Be Considered in Applying FASB
interpretation No. 46(R)”
|
In
April 2006, the
FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
determine the variability to be considered in applying FASB interpretation
No.
46 (revised December 2003). JCP&L adopted FIN 46(R) in the first quarter of
2004, consolidating VIE’s when JCP&L or one of its subsidiaries is
determined to be the VIE’s primary beneficiary. The variability that is
considered in applying interpretation 46(R) affects the determination of (a)
whether the entity is a VIE; (b) which interests are variable interests in
the
entity; and (c) which party, if any, is the primary beneficiary of the VIE.
This
FSP states that the variability to be considered shall be based on an analysis
of the design of the entity, involving two steps:
Step
1:
|
Analyze
the
nature of the risks in the entity
|
Step
2:
|
Determine
the
purpose(s) for which the entity was created and determine the variability
the entity is designed to create and pass along to its interest
holders.
|
After
determining
the variability to consider, the reporting enterprise can determine which
interests are designed to absorb that variability. The guidance in this FSP
is
applied prospectively to all entities (including newly created entities) with
which that enterprise first becomes involved and to all entities previously
required to be analyzed under interpretation 46(R) when a reconsideration event
has occurred after July 1, 2006. JCP&L does not expect this Statement
to have a material impact on its financial statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. JCP&L is
currently evaluating the impact of this Statement.
METROPOLITAN
EDISON
COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE
INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
356,181
|
|
$
|
333,180
|
|
$
|
949,613
|
|
$
|
892,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
184,508
|
|
|
186,148
|
|
|
487,465
|
|
|
467,911
|
|
Other
operating costs
|
|
|
108,740
|
|
|
81,774
|
|
|
229,394
|
|
|
192,892
|
|
Provision
for
depreciation
|
|
|
10,197
|
|
|
9,323
|
|
|
31,390
|
|
|
32,221
|
|
Amortization
of regulatory assets
|
|
|
33,560
|
|
|
32,853
|
|
|
89,277
|
|
|
86,760
|
|
Deferral
of
new regulatory assets
|
|
|
(44,213
|
)
|
|
-
|
|
|
(89,794
|
)
|
|
-
|
|
General
taxes
|
|
|
21,362
|
|
|
19,906
|
|
|
60,578
|
|
|
56,201
|
|
Total
expenses
|
|
|
314,154
|
|
|
330,004
|
|
|
808,310
|
|
|
835,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
42,027
|
|
|
3,176
|
|
|
141,303
|
|
|
56,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
8,053
|
|
|
9,109
|
|
|
25,767
|
|
|
27,578
|
|
Miscellaneous
income
|
|
|
1,477
|
|
|
2,296
|
|
|
5,881
|
|
|
6,725
|
|
Interest
expense
|
|
|
(12,291
|
)
|
|
(10,891
|
)
|
|
(35,546
|
)
|
|
(33,512
|
)
|
Capitalized
interest
|
|
|
355
|
|
|
150
|
|
|
966
|
|
|
401
|
|
Total
other
income (expense)
|
|
|
(2,406
|
)
|
|
664
|
|
|
(2,932
|
)
|
|
1,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
39,621
|
|
|
3,840
|
|
|
138,371
|
|
|
57,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
14,631
|
|
|
2,835
|
|
|
55,390
|
|
|
24,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
24,990
|
|
|
1,005
|
|
|
82,981
|
|
|
33,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
83
|
|
|
84
|
|
|
251
|
|
|
252
|
|
Unrealized
gain on available for sale securities
|
|
|
-
|
|
|
67
|
|
|
-
|
|
|
67
|
|
Other
comprehensive income
|
|
|
83
|
|
|
151
|
|
|
251
|
|
|
319
|
|
Income
tax
expense related to other comprehensive income
|
|
|
34
|
|
|
62
|
|
|
104
|
|
|
132
|
|
Other
comprehensive income, net of tax
|
|
|
49
|
|
|
89
|
|
|
147
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
25,039
|
|
$
|
1,094
|
|
$
|
83,128
|
|
$
|
33,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral part of these
statements.
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
September
30,
|
|
December
31,
|
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
$
|
133
|
|
$
|
120
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,301,000 and $4,352,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
|
130,777
|
|
|
129,854
|
|
Associated
companies
|
|
|
|
6,179
|
|
|
37,267
|
|
Other
|
|
|
|
11,265
|
|
|
8,780
|
|
Notes
receivable from associated companies
|
|
|
|
32,720
|
|
|
27,867
|
|
Prepayments
and other
|
|
|
|
16,159
|
|
|
7,912
|
|
|
|
|
|
197,233
|
|
|
211,800
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
|
1,901,091
|
|
|
1,856,425
|
|
Less
-
Accumulated provision for depreciation
|
|
|
|
730,720
|
|
|
721,566
|
|
|
|
|
|
1,170,371
|
|
|
1,134,859
|
|
Construction
work in progress
|
|
|
|
19,669
|
|
|
20,437
|
|
|
|
|
|
1,190,040
|
|
|
1,155,296
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
|
256,198
|
|
|
234,854
|
|
Other
|
|
|
|
1,363
|
|
|
1,453
|
|
|
|
|
|
257,561
|
|
|
236,307
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
860,227
|
|
|
864,438
|
|
Regulatory
assets
|
|
|
|
364,889
|
|
|
309,556
|
|
Prepaid
pension costs
|
|
|
|
94,205
|
|
|
89,005
|
|
Other
|
|
|
|
66,417
|
|
|
51,285
|
|
|
|
|
|
1,385,738
|
|
|
1,314,284
|
|
|
|
|
$
|
3,030,572
|
|
$
|
2,917,687
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
$
|
50,000
|
|
$
|
100,000
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
|
181,871
|
|
|
140,240
|
|
Other
|
|
|
|
75,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
|
14,004
|
|
|
37,220
|
|
Other
|
|
|
|
49,170
|
|
|
27,507
|
|
Accrued
taxes
|
|
|
|
7,460
|
|
|
17,911
|
|
Accrued
interest
|
|
|
|
9,130
|
|
|
9,438
|
|
Other
|
|
|
|
22,905
|
|
|
24,274
|
|
|
|
|
|
409,540
|
|
|
356,590
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
|
859,000
shares
outstanding
|
|
|
|
1,282,846
|
|
|
1,287,093
|
|
Accumulated
other comprehensive loss
|
|
|
|
(1,422
|
)
|
|
(1,569
|
)
|
Retained
earnings
|
|
|
|
108,556
|
|
|
30,575
|
|
Total
common
stockholder's equity
|
|
|
|
1,389,980
|
|
|
1,316,099
|
|
Long-term
debt
and other long-term obligations
|
|
|
|
541,979
|
|
|
591,888
|
|
|
|
|
|
1,931,959
|
|
|
1,907,987
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
|
375,544
|
|
|
344,929
|
|
Accumulated
deferred investment tax credits
|
|
|
|
9,444
|
|
|
10,043
|
|
Nuclear
fuel
disposal costs
|
|
|
|
40,958
|
|
|
39,567
|
|
Asset
retirement obligations
|
|
|
|
148,782
|
|
|
142,020
|
|
Retirement
benefits
|
|
|
|
56,674
|
|
|
57,809
|
|
Other
|
|
|
|
57,671
|
|
|
58,742
|
|
|
|
|
|
689,073
|
|
|
653,110
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10) |
|
|
|
|
|
|
|
|
|
|
|
$
|
3,030,572
|
|
$
|
2,917,687
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral part of these balance
sheets.
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
|
$
|
82,981
|
|
$
|
33,144
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
31,390
|
|
|
32,221
|
|
Amortization
of regulatory assets
|
|
|
|
89,277
|
|
|
86,760
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
|
(53,406
|
)
|
|
(48,156
|
)
|
Deferral
of
new regulatory assets
|
|
|
|
(89,794
|
)
|
|
-
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
|
27,895
|
|
|
(10,336
|
)
|
Accrued
compensation and retirement benefits
|
|
|
|
(6,007
|
)
|
|
(4,506
|
)
|
Cash
collateral to suppliers
|
|
|
|
(21,500
|
)
|
|
-
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
|
27,680
|
|
|
113,298
|
|
Prepayments
and other current assets
|
|
|
|
(8,247
|
)
|
|
(2,228
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
|
(1,553
|
)
|
|
(44,505
|
)
|
Accrued
taxes
|
|
|
|
(10,451
|
)
|
|
(9,710
|
)
|
Accrued
interest
|
|
|
|
(308
|
)
|
|
(2,156
|
)
|
Other
|
|
|
|
(1,777
|
)
|
|
2,602
|
|
Net
cash
provided from operating activities
|
|
|
|
66,180
|
|
|
146,428
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
|
116,624
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
|
(100,000
|
)
|
|
(37,830
|
)
|
Short-term
borrowings, net
|
|
|
|
-
|
|
|
(3,335
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
(5,000
|
)
|
|
(44,000
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
|
11,624
|
|
|
(85,165
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
|
(65,332
|
)
|
|
(56,075
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
|
151,593
|
|
|
119,207
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
|
(158,705
|
)
|
|
(126,319
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
|
(4,853
|
)
|
|
2,267
|
|
Other
|
|
|
|
(494
|
)
|
|
(343
|
)
|
Net
cash used
for investing activities
|
|
|
|
(77,791
|
)
|
|
(61,263
|
)
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
|
13
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
|
120
|
|
|
120
|
|
Cash
and cash
equivalents at end of period
|
|
|
$
|
133
|
|
$
|
120
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral part of these
statements.
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Metropolitan Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of Metropolitan Edison Company and
its
subsidiaries as of September 30, 2006, and the related consolidated statements
of income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2006 and 2005 and the consolidated statements of
cash flows for the nine-month periods ended September 30, 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.
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 9 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
October
31,
2006
|
METROPOLITAN
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
Met-Ed
is a wholly
owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business
in
eastern Pennsylvania, providing regulated electric transmission and distribution
services. Met-Ed also provides generation service to those customers electing
to
retain Met-Ed as their power supplier.
Results
of Operations
Net
income in the
third quarter of 2006 increased to $25 million from $1 million in the third
quarter of 2005. This increase reflects the deferral of new regulatory assets
and higher revenues, partially offset by higher other operating costs as
discussed below. For the first nine months of 2006, net income increased to
$83
million from $33 million in the same period of 2005. This increase reflects
the
deferral of new regulatory assets and higher revenues, partially offset by
higher purchased power costs, amortization of regulatory assets, general taxes
and other operating costs as discussed below.
Revenues
Revenues
increased
by $23 million, or 6.9%, in the third quarter of 2006 and $58 million, or 6.4%,
in the first nine months of 2006, compared with the same periods of 2005.
Increases in both periods were primarily due to higher retail generation
electric revenues ($12 million for the third quarter and $39 million for the
first nine months of 2006), which reflected higher composite prices in all
customer classes. For the third quarter of 2006, higher KWH sales to industrial
customers were partially offset by lower KWH sales to residential and commercial
customers. For the first nine months of 2006, higher KWH sales to industrial
and
commercial customers were partially offset by lower KWH sales to residential
customers. Industrial KWH sales, for both periods, increased primarily due
to
the return of customers to Met-Ed from alternative suppliers. Sales by
alternative suppliers as a percent of total industrial sales in Met-Ed’s
franchise area decreased by 9.7 percentage points in the third quarter of 2006
and 12.6 percentage points in the first nine months of 2006. Lower KWH sales
to
residential customers, for both periods of 2006, and to commercial customers,
for the third quarter of 2006, primarily resulted from milder weather in 2006
as
compared with the same periods of 2005.
Revenues
from
distribution throughput essentially remained unchanged for the third quarter
of
2006 as compared with the same period of 2005. This was the result of higher
composite unit prices being substantially offset by a decrease in total KWH
deliveries. The decrease in KWH deliveries primarily resulted from milder
weather in the third quarter of 2006 (a 19.8% decrease in cooling degree days)
compared with the same period in 2005. For the first nine months of 2006,
revenues from distribution throughput decreased by $1 million compared with
the
same period of 2005. A 1.3% decrease in KWH deliveries was partially offset
by
higher composite prices. KWH deliveries decreased as a result from milder
weather in the first nine months of 2006 (a 17.1% decrease in cooling degree
days and a 15.7% decrease in heating degree days) as compared with the same
period in 2005.
For
both periods of
2006, transmission revenues increased primarily due to higher transmission
prices, which also resulted in higher transmission expenses as discussed below.
Rental revenues also increased by $3 million, for both periods of 2006, due
to
higher charges for the joint use of Met-Ed’s utility poles. In the first nine
months of 2006, other revenues also increased due to a $2 million increase
in the payment received in the first quarter of 2006 under a contract provision
associated with the prior sale of TMI Unit 1, compared to the same period in
2005. Under the contract, additional payments are received if subsequent energy
prices rise above specified levels. This payment is credited to Met-Ed’s
customers, resulting in no net earnings effect.
Changes
in KWH sales
by customer class in the third quarter and the first nine months of 2006
compared with the same periods in 2005 are summarized in the following
table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
|
Residential
|
|
|
(1.9
|
)%
|
|
(1.9
|
)%
|
Commercial
|
|
|
(0.2
|
)%
|
|
1.3
|
%
|
Industrial
|
|
|
8.2
|
%
|
|
11.9
|
%
|
Total
Retail Electric Generation Sales
|
|
|
1.3
|
%
|
|
2.8
|
%
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
(2.1
|
)%
|
|
(2.1
|
)%
|
Commercial
|
|
|
(0.9
|
)%
|
|
0.4
|
%
|
Industrial
|
|
|
(2.3
|
)%
|
|
(2.3
|
)%
|
Total
Distribution Deliveries
|
|
|
(1.8
|
)%
|
|
(1.3
|
)%
|
|
|
|
|
|
|
|
|
Expenses
Total expenses decreased by $16 million and $28 million in the third quarter
and
the first nine months of 2006, respectively, compared with the same periods
of
2005. The following table presents changes from the prior year by expense
category:
|
|
Three
|
|
Nine
|
|
Expenses
- Changes
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
(2
|
)
|
$
|
20
|
|
Other
operating costs
|
|
|
27
|
|
|
36
|
|
Provision
for
depreciation
|
|
|
1
|
|
|
(1
|
)
|
Amortization
of regulatory assets
|
|
|
1
|
|
|
3
|
|
Deferral
of
new regulatory assets
|
|
|
(44
|
)
|
|
(90
|
)
|
General
taxes
|
|
|
1
|
|
|
4
|
|
Net
decrease in expenses
|
|
$
|
(16
|
)
|
$
|
(28
|
)
|
|
|
|
|
|
|
|
|
Purchased
power
costs decreased by $2 million in the third quarter of 2006 due to lower
composite unit prices, partially offset by increased purchases to meet higher
customer demand and a $10 million charge related to incremental NUG costs
deferred in 2005 under a revised accounting methodology. For the first nine
months of 2006, purchased power costs increased by $20 million due to increased
purchases to meet higher customer demand and higher composite unit prices,
offset by increased NUG cost deferrals.
Other
operating
costs increased for both periods primarily due to higher transmission expenses,
which increased as a result of the higher transmission prices discussed above.
The deferral of new regulatory assets, for both periods, reflected the
May 4, 2006 PPUC approval of Met-Ed’s request to defer certain 2006
transmission-related costs (see Regulatory Matters for further discussion).
For
both periods, general taxes increased primarily due to higher gross receipt
taxes.
Capital
Resources and Liquidity
Met-Ed’s
cash
requirements for the remainder of 2006 for expenses and construction
expenditures are expected to be met with a combination of cash from operations
and short-term credit arrangements.
Changes
in Cash
Position
As
of September 30,
2006, Met-Ed had $133,000 of cash and cash equivalents compared with $120,000
as
of December 31, 2005. The major sources for changes in these balances are
summarized below.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities in the first nine months of 2006 and 2005 were as
follows:
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings
(1)
|
|
$
|
82
|
|
$
|
89
|
|
Working
capital and other
|
|
|
(16
|
)
|
|
57
|
|
Net
cash
provided from operating activities
|
|
$
|
66
|
|
$
|
146
|
|
|
|
|
|
|
|
|
|
(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. Met-Ed believes that cash earnings is a useful financial measure because
it provides investors and management with an additional means of evaluating
its
cash-based operating performance. Generally, a non-GAAP financial measure is
a
numerical measure of a company’s historical or future financial performance,
financial position, or cash flows that either excludes or includes amounts,
or
is subject to adjustment that has the effect of excluding or including amounts,
that are not normally excluded or included in the most directly comparable
measure calculated and presented in accordance with GAAP. In addition, cash
earnings (non-GAAP) are not defined under GAAP. Management believes presenting
this non-GAAP measure provides useful information to investors in assessing
Met-Ed’s operating performance from a cash perspective without the effects of
material unusual economic events. Met-Ed’s management frequently references
these non-GAAP financial measures in its decision-making, using them to
facilitate historical and ongoing performance comparisons as well as comparisons
to the performance of peer companies. These non-GAAP measures should be
considered in addition to, and not as a substitute for, their most directly
comparable financial measures prepared in accordance with GAAP.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
83
|
|
$
|
33
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
31
|
|
|
32
|
|
Amortization
of regulatory assets
|
|
|
89
|
|
|
87
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(53
|
)
|
|
(49
|
)
|
Deferral
of
new regulatory assets
|
|
|
(90
|
)
|
|
-
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
28
|
|
|
(10
|
)
|
Other
non-cash
charges
|
|
|
(6
|
)
|
|
(4
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
82
|
|
$
|
89
|
|
The
$7 million
decrease in cash earnings is described above under “Results of Operations.” The
$73 million working capital change primarily resulted from an $86 million
decrease in cash provided from the collection of receivables, a $22 million
increase in cash collateral returned to suppliers, a $6 million increase in
prepayments, and a $4 million decrease in other accrued liabilities, offset
by
$43 million in decreased outflows for accounts payable and a $2 million increase
in accrued interest.
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities was $12 million in first nine months of 2006 compared
to $85 million in net cash used for financing activities in the same period
of 2005. The increase primarily reflects a $120 million increase in
short-term borrowings and a $39 million decrease in common stock dividend
payments to FirstEnergy in the first nine months of 2006, offset by a $62
million increase in long-term debt redemptions.
As
of September 30,
2006, Met-Ed had approximately $33 million of cash and temporary
investments (which included short-term notes receivable from associated
companies) and $257 million of short-term borrowings. Met-Ed has
authorization from the FERC to incur short-term debt up to $250 million and
authorization from the PPUC to incur money pool borrowings up to
$300 million. In addition, Met-Ed has $80 million of available
accounts receivable financing facilities as of September 30, 2006 through
Met-Ed Funding LLC, Met-Ed’s wholly owned subsidiary. As a separate legal entity
with separate creditors, Met-Ed Funding would have to satisfy its obligations
to
creditors before any of its remaining assets could be made available to Met-Ed.
In June 2006, the facility was renewed until June 28, 2007. The annual
facility fee is 0.125% on the entire finance limit. As of September 30, 2006
the
facility was drawn for $75 million.
Under
the terms of
Met-Ed’s senior note indenture, FMBs may no longer be issued so long as senior
notes are outstanding. As of September 30, 2006, Met-Ed had the capability
to issue $642 million of additional senior notes based upon FMB collateral.
Met-Ed had no restrictions on the issuance of preferred stock.
On
August 24, 2006,
Met-Ed, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as
Borrowers, entered into a new $2.75 billion five-year revolving credit facility,
which replaced the prior $2 billion credit facility. FirstEnergy may
request an increase in the total commitments available under the new facility
up
to a maximum of $3.25 billion. Commitments
under
the new facility are available until August 24, 2011, unless the lenders
agree, at the request of the Borrowers, to two additional one-year extensions.
Generally, borrowings under the facility must be repaid within 364 days.
Available amounts for each Borrower are subject to a specified sub-limit, as
well as applicable regulatory and other limitations. Met-Ed’s
borrowing
limit under the facility is $250 million.
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 the existing credit facilities and accounts receivable financing
facilities totaled $255 million as of September 30, 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
September 30, 2006, Met-Ed’s debt to total capitalization as defined under
the revolving credit facility was 38%.
The
facility does
not contain any provisions that either restrict Met-Ed’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 Met-Ed's credit ratings.
Met-Ed
has the
ability to borrow from its regulated affiliates and FirstEnergy to meet its
short-term working capital requirements. FESC administers this money pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well
as
proceeds available from bank borrowings. Companies receiving a loan under the
money pool agreements must repay the principal amount of such a loan, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the first nine months of 2006 was
5.09%.
Met-Ed’s
access to
the capital markets and the costs of financing are dependent on the ratings
of
its securities and that of FirstEnergy. As of September 30, 2006, Met-Ed’s
and FirstEnergy’s ratings outlook from S&P on all securities was stable. The
ratings outlook from Moody’s and Fitch on all securities is
positive.
Cash
Flows From
Investing Activities
In
the final nine
months of 2006, Met-Ed’s cash used for investing activities totaled
$78 million, compared with $61 million in the same period of 2005. The
increase primarily resulted from a $9 million increase in property
additions and a $7 million increase in loans to associated companies.
Expenditures for property additions primarily support Met-Ed’s energy delivery
operations and reliability initiatives.
During
the last
quarter of 2006, capital requirements for property additions are expected to
be
about $15 million. This cash requirement is expected to be satisfied from a
combination of internal cash and short-term credit arrangements.
Met-Ed's
capital
spending for the period 2006 through 2010 is expected to be about
$365 million, of which approximately $81 million applies to 2006. The
capital spending is primarily for property additions supporting the distribution
of electricity.
Market
Risk Information
Met-Ed
uses various
market risk sensitive instruments, including derivative contracts, primarily
to
manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee,
comprised of members of senior management, provides general oversight to risk
management activities.
Commodity
Price
Risk
Met-Ed
is exposed to
market risk primarily due to fluctuations in electricity, energy transmission,
natural gas, coal, and emission prices. To manage the volatility relating to
these exposures, it uses a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts, and swaps. The
derivatives are used principally for hedging purposes. All derivatives that
fall
within the scope of SFAS 133 must be recorded at their fair value and marked
to
market. The majority of Met-Ed’s derivative hedging contracts qualify for the
normal purchase and normal sale exception under SFAS 133. Contracts that are
not
exempt from such treatment include the power purchase agreements with NUG
entities that were structured pursuant to the Public Utility Regulatory Policies
Act of 1978. These non-trading contracts had been adjusted to fair value at
the
end of each quarter, with a corresponding regulatory asset recognized for
above-market costs. On April 1, 2006, Met-Ed elected to apply the normal
purchase and normal sale exception to certain NUG power purchase agreements
having an above-market fair value of $1 million (included in “Other” in the
table below) in accordance with guidance in DIG C20. The change in the fair
value of commodity derivative contracts related to energy production during
the
third quarter and first nine months of 2006 is summarized in the following
table:
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
September
30, 2006
|
|
September
30, 2006
|
|
of
Commodity Derivative Contracts
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
(In
millions)
|
|
Change
in the Fair Value of
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net asset at beginning of period
|
$
|
23
|
|
$
|
-
|
|
$
|
23
|
|
$
|
27
|
|
$
|
-
|
|
$
|
27
|
|
New
contract
value when entered
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
-
|
|
|
-
|
|
|
-
|
|
|
4
|
|
|
-
|
|
|
4
|
|
Change
in
techniques/assumptions
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(9
|
)
|
|
-
|
|
|
(9
|
)
|
Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Net
Assets - Derivative Contracts
at
End
of Period (1)
|
$
|
23
|
|
$
|
-
|
|
$
|
23
|
|
$
|
23
|
|
$
|
-
|
|
$
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
(2
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OCI
(pre-tax)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Regulatory
liability
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3
|
|
$
|
-
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes
$23 million
in non-hedge commodity derivative contract, which is offset by a regulatory
liability.
(2) 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
September 30, 2006 as follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
$
|
23
|
|
$
|
-
|
|
$
|
23
|
|
Other
noncurrent liabilities
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
assets
|
|
$
|
23
|
|
$
|
-
|
|
$
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
The
valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, Met-Ed relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. Met-Ed uses these results to develop estimates of fair value
for financial reporting purposes and for internal management decision making.
Sources of information for the valuation of commodity derivative contracts
as of
September 30, 2006 are summarized by year in the following
table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
2006(1)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Other
external
sources (2)
(3)
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
4
|
|
$
|
-
|
|
$
|
-
|
|
$
|
19
|
|
Prices
based
on models(3)
|
|
|
-
|
|
|
- |
|
|
- |
|
|
- |
|
|
4
|
|
|
-
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
4
|
|
$
|
4
|
|
$
|
-
|
|
$
|
23
|
|
(1) For
the last quarter
of 2006.
(2) Broker
quote
sheets.
(3) Includes
$23 million
from a non-hedge commodity derivative contract that is offset by a regulatory
liability and does not affect earnings.
Met-Ed
performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift in quoted market prices
in
the near term on both of Met-Ed’s trading and non-trading derivative instruments
would not have had a material effect on its consolidated financial position
or
cash flows as of September 30, 2006. Met-Ed estimates that if energy
commodity prices experienced an adverse 10% change, net income for the next
twelve months would not change, as prices for all commodity positions are
already above the contract price caps.
Equity
Price
Risk
Included
in Met-Ed's
nuclear decommissioning trusts are marketable equity securities carried at
their
market value of approximately $153 million and
$142 million as of September 30, 2006 and December 31, 2005,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $15 million
reduction in fair value as of September 30, 2006.
Regulatory
Matters
Regulatory assets are costs which have been authorized by 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 Met-Ed’s
transition plan and rate restructuring plan. Met-Ed’s regulatory assets as of
September 30, 2006 and December 31, 2005 were $365 million and
$310 million, respectively.
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 and the companies filed initial
testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this
proceeding with the April 10, 2006 comprehensive rate filing proceeding
discussed below. Met-Ed and Penelec are unable to predict the outcome of this
matter.
In an October 16, 2003 order, the PPUC approved June 30, 2004 as the
date for Met-Ed's NUG trust fund refunds. The PPUC order also denied its
accounting treatment request regarding the CTC rate/shopping credit swap by
requiring Met-Ed to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed
filed an Objection with the Commonwealth Court asking that the Court reverse
this PPUC finding; a Commonwealth Court judge subsequently denied its Objection
on October 27, 2003 without explanation. On October 31, 2003, Met-Ed
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 Objection was intended to be denied
on the merits. The Reargument Brief before the Commonwealth Court was filed
on
January 28, 2005. Oral arguments were held on June 8, 2006. On July
19, 2006, the Commonwealth Court issued its decision affirming the PPUC’s prior
orders. Although the decision denied the appeal of Met-Ed, it had previously
accounted for the treatment of costs required by the PPUC’s October 2003
orders.
Met-Ed purchases a portion of its 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 under its contracts with NUGs and other unaffiliated
suppliers. The FES arrangement reduces Met-Ed'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 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
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 its PLR obligations
for
which Committed Resources (i.e., non-utility generation under contract to
Met-Ed, Met-Ed-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 an agent for Met-Ed in procuring the services under
1 (b) above; and
3. The
pricing
provision of the wholesale power sales agreement shall remain unchanged provided
Met-Ed complies 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 procures 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 its PLR obligations for
2008, 2009 and 2010, respectively, for which Committed Resources have not been
obtained from the market. On September 26, 2006, Met-Ed successfully
conducted a competitive RFP for 33% of its PLR obligation for which Committed
Resources had not been obtained for the period December 1, 2006 through
December 31, 2008.
The wholesale power sales agreement, as modified by the Tolling Agreement,
requires Met-Ed to satisfy the portion of its 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 purchased power costs could materially increase. If Met-Ed
were to replace the entire FES supply at current market power prices without
corresponding regulatory authorization to increase its generation prices to
customers, it would likely incur a significant increase in operating expenses
and experience a material deterioration in credit quality metrics. Under such
a
scenario, Met-Ed'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, further
reduce, 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
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 preferred
approach involving accounting deferrals is approved, the filing would increase
annual revenues by $216 million. That filing includes, among other things,
a request to charge customers for an increasing amount of market priced power
procured through a CBP 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 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 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 of $37 million annually. The PPUC suspended the effective
date (June 10, 2006) of these rate changes for seven months after the
filing as permitted under Pennsylvania law. If the PPUC adopts the overall
positions taken in the intervenors’ testimony as filed, this would have a
material adverse effect on the financial statements of FirstEnergy and Met-Ed.
Hearings were held in late August 2006 and all reply briefs were filed by
October 6, 2006. The ALJ’s recommended decision is due by November 8, 2006
and the PPUC decision is expected by January 12, 2007.
The
annual goodwill
impairment analysis performed in the third quarter of 2006 assumed management's
best estimate of the rate increases that are expected to be granted in January
2007 under Met-Ed’s comprehensive rate filing. If the PPUC authorizes less than
the amounts assumed, an additional impairment analysis would be performed at
that time and this could result in a future goodwill impairment loss that could
be material. If rate relief were completely denied, it is estimated that
approximately $604 million of Met-Ed’s goodwill would be impaired and
written off. However, no adjustment to FirstEnergy’s goodwill on a consolidated
basis would be recognized in that circumstance because the fair value of its
regulated segment (which represents FirstEnergy's reporting unit to evaluate
goodwill) would continue to exceed the carrying value of its investment in
the
segment.
As of September 30, 2006, Met-Ed's regulatory deferrals pursuant to the
1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
FirstEnergy/GPU Merger Settlement Stipulation was $297 million. The PPUC
recently conducted a review and audit of a modification to the NUG purchased
power stranded cost accounting methodology for Met-Ed. On August 18, 2006,
a
PPUC Order was entered requiring Met-Ed to reflect the deferred NUG cost
balances as if the stranded cost accounting methodology modification had not
been implemented. As a result of the PPUC’s Order, Met-Ed recognized a pre-tax
charge of approximately $10.3 million in the third quarter of 2006, representing
incremental costs deferred under the revised methodology in 2005. Met-Ed
continues to believe that the stranded cost accounting methodology modification
is appropriate and filed a petition with the PPUC pursuant to its Order for
authorization to reflect the stranded cost accounting methodology modification
effective January 1, 1999.
On
January 12,
2005, Met-Ed 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 all intervened in the case. Met-Ed sought to consolidate this
proceeding (and modified its request to provide deferral of 2006
transmission-related costs only) with the comprehensive rate filing it made
on
April 10, 2006 as described above. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Met-Ed has deferred approximately
$90 million, representing transmission costs that were incurred from
January 1, 2006 through September 30, 2006. On June 5, 2006, the OCA
filed before the Commonwealth Court a petition for review of the PPUC’s approval
of the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s
motion to quash the OCA’s appeal. The ratemaking treatment of the deferrals will
be determined in the comprehensive rate filing proceeding discussed above.
On November 18, 2004, the FERC issued an order eliminating the RTOR for
transmission service between the MISO and PJM regions. The FERC also ordered
MISO, PJM and the transmission owners within MISO and PJM to submit compliance
filings containing a SECA mechanism 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 was held in May 2006. Initial
briefs were submitted on June 9, 2006, and reply briefs were filed on June
27, 2006. The Presiding Judge issued an Initial Decision on August 10,
2006, rejecting the compliance filings made by the RTOs and transmission owners,
ruling on various issues and directing new compliance filings. This decision
is
subject to review and approval by the FERC. Briefs addressing the Initial
Decision were filed on September 11, 2006 and October 20, 2006. A
final order could be issued by the FERC by the end of 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 refund 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. Hearings in the PJM rate
design case concluded in April 2006. On July 13, 2006, an Initial Decision
was
issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of
all PJM transmission facilities should be recovered through a postage stamp
rate. The ALJ recommended an April 1, 2006 effective date for this change in
rate design. If the FERC accepts this recommendation, the transmission rate
applicable to many load zones in PJM would increase. FirstEnergy believes that
significant additional transmission revenues would have to be recovered from
the
JCP&L, Met-Ed and Penelec transmission zones within PJM. JCP&L, Met-Ed
and Penelec, as part of the Responsible Pricing Alliance, filed a brief
addressing the Initial Decision on August 14, 2006 and September 5,
2006. The case will be reviewed by the FERC with a decision anticipated in
the
fourth quarter of 2006.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in Pennsylvania including a more detailed
discussion of reliability initiatives, including actions by the PPUC that impact
Met-Ed.
Environmental
Matters
Met-Ed accrues environmental liabilities when it concludes that it is probable
that it has an obligation for such costs and can reasonably determine the amount
of such costs. Unasserted claims are reflected in Met-Ed’s determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.
Met-Ed has been named as a PRP at waste disposal sites, which may require
cleanup under the Comprehensive Environmental Response, Compensation, and
Liability Act of 1980. Allegations of disposal of hazardous substances at
historical sites and the liability involved are often unsubstantiated and
subject to dispute; however, federal law provides that all PRPs for a particular
site 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 September 30, 2006, based on estimates of
the total costs of cleanup, Met-Ed’s proportionate responsibility for such
costs, and the financial ability of other unaffiliated entities to pay.
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
There are various lawsuits, claims (including claims for asbestos exposure)
and
proceedings related to Met-Ed’s normal business operations pending against
Met-Ed. The other material items not otherwise discussed below are described
in
Note 10(C) to the consolidated financial statements.
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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
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.
New
Accounting Standards and Interpretations
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In September 2006, the SEC issued SAB 108, which provides interpretive guidance
on how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments will
need to be reconsidered using both the rollover and iron curtain methods. This
guidance will be effective for Met-Ed in the fourth quarter of 2006. Met-Ed
does
not expect this Statement to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157, that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
Met-Ed is currently evaluating the impact of this Statement on its financial
statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for Met-Ed as of December 31, 2006. Met-Ed
is
currently evaluating the impact of this Statement on its financial
statements.
|
FSP
FIN
46(R)-6 - “Determining the Variability to Be Considered in Applying FASB
interpretation No. 46(R)”
|
In
April 2006, the
FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
determine the variability to be considered in applying FASB interpretation
No.
46 (revised December 2003). Met-Ed adopted FIN 46(R) in the first quarter of
2004, consolidating VIE’s when Met-Ed or one of its subsidiaries is determined
to be the VIE’s primary beneficiary. The variability that is considered in
applying interpretation 46(R) affects the determination of (a) whether the
entity is a VIE; (b) which interests are variable interests in the entity;
and
(c) which party, if any, is the primary beneficiary of the VIE. This FSP states
that the variability to be considered shall be based on an analysis of the
design of the entity, involving two steps:
Step
1:
|
Analyze
the
nature of the risks in the entity
|
Step
2:
|
Determine
the
purpose(s) for which the entity was created and determine the variability
the entity is designed to create and pass along to its interest
holders.
|
After
determining
the variability to consider, the reporting enterprise can determine which
interests are designed to absorb that variability. The guidance in this FSP
is
applied prospectively to all entities (including newly created entities) with
which that enterprise first becomes involved and to all entities previously
required to be analyzed under interpretation 46(R) when a reconsideration event
has occurred after July 1, 2006. Met-Ed does not expect this Statement to
have a material impact on its financial statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. Met-Ed is
currently evaluating the impact of this Statement.
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
303,420
|
|
$
|
290,451
|
|
$
|
860,171
|
|
$
|
846,477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
165,921
|
|
|
178,090
|
|
|
474,437
|
|
|
467,639
|
|
Other
operating costs
|
|
|
65,165
|
|
|
66,417
|
|
|
151,640
|
|
|
183,024
|
|
Provision
for
depreciation
|
|
|
11,828
|
|
|
12,736
|
|
|
36,269
|
|
|
37,721
|
|
Amortization
of regulatory assets
|
|
|
13,060
|
|
|
12,627
|
|
|
40,854
|
|
|
38,930
|
|
Deferral
of
new regulatory assets
|
|
|
(9,235
|
)
|
|
-
|
|
|
(21,050
|
)
|
|
-
|
|
General
taxes
|
|
|
18,593
|
|
|
17,552
|
|
|
55,440
|
|
|
51,892
|
|
Total
expenses
|
|
|
265,332
|
|
|
287,422
|
|
|
737,590
|
|
|
779,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
38,088
|
|
|
3,029
|
|
|
122,581
|
|
|
67,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
2,182
|
|
|
2,088
|
|
|
6,179
|
|
|
3,356
|
|
Interest
expense
|
|
|
(11,840
|
)
|
|
(9,841
|
)
|
|
(33,975
|
)
|
|
(29,579
|
)
|
Capitalized
interest
|
|
|
363
|
|
|
285
|
|
|
1,132
|
|
|
674
|
|
Total
other
income (expense)
|
|
|
(9,295
|
)
|
|
(7,468
|
)
|
|
(26,664
|
)
|
|
(25,549
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
28,793
|
|
|
(4,439
|
)
|
|
95,917
|
|
|
41,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAX EXPENSE (BENEFIT)
|
|
|
10,733
|
|
|
(2,070
|
)
|
|
39,251
|
|
|
16,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
18,060
|
|
|
(2,369
|
)
|
|
56,666
|
|
|
24,852
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
17
|
|
|
17
|
|
|
49
|
|
|
49
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
14
|
|
|
18
|
|
|
(4
|
)
|
|
(3
|
)
|
Other
comprehensive income
|
|
|
31
|
|
|
35
|
|
|
45
|
|
|
46
|
|
Income
tax
expense related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
13
|
|
|
20
|
|
|
20
|
|
|
20
|
|
Other
comprehensive income, net of tax
|
|
|
18
|
|
|
15
|
|
|
25
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME (LOSS)
|
|
$
|
18,078
|
|
$
|
(2,354
|
)
|
$
|
56,691
|
|
$
|
24,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Pennsylvania
Electric Company are an integral part of these
statements.
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
September
30,
|
|
December
31,
|
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
$
|
47
|
|
$
|
35
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,920,000 and $4,184,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
|
122,232
|
|
|
129,960
|
|
Associated
companies
|
|
|
|
5,208
|
|
|
18,626
|
|
Other
|
|
|
|
11,228
|
|
|
12,800
|
|
Notes
receivable from associated companies
|
|
|
|
20,599
|
|
|
17,624
|
|
Prepayments
and other
|
|
|
|
10,912
|
|
|
7,936
|
|
|
|
|
|
170,226
|
|
|
186,981
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
|
2,119,123
|
|
|
2,043,885
|
|
Less
-
Accumulated provision for depreciation
|
|
|
|
801,695
|
|
|
784,494
|
|
|
|
|
|
1,317,428
|
|
|
1,259,391
|
|
Construction
work in progress
|
|
|
|
21,704
|
|
|
30,888
|
|
|
|
|
|
1,339,132
|
|
|
1,290,279
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
|
120,107
|
|
|
113,368
|
|
Non-utility
generation trusts
|
|
|
|
98,864
|
|
|
96,761
|
|
Other
|
|
|
|
532
|
|
|
918
|
|
|
|
|
|
219,503
|
|
|
211,047
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
873,819
|
|
|
882,344
|
|
Prepaid
pension costs
|
|
|
|
93,643
|
|
|
89,637
|
|
Other
|
|
|
|
36,258
|
|
|
38,289
|
|
|
|
|
|
1,003,720
|
|
|
1,010,270
|
|
|
|
|
$
|
2,732,581
|
|
$
|
2,698,577
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
$
|
216,437
|
|
$
|
261,159
|
|
Other
|
|
|
|
66,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
|
12,429
|
|
|
33,770
|
|
Other
|
|
|
|
44,063
|
|
|
38,277
|
|
Accrued
taxes
|
|
|
|
17,864
|
|
|
27,905
|
|
Accrued
interest
|
|
|
|
14,373
|
|
|
8,905
|
|
Other
|
|
|
|
19,489
|
|
|
19,756
|
|
|
|
|
|
390,655
|
|
|
389,772
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
$20 par value, authorized 5,400,000 shares-
|
|
|
|
|
|
|
|
|
5,290,596
shares outstanding
|
|
|
|
105,812
|
|
|
105,812
|
|
Other
paid-in
capital
|
|
|
|
1,197,480
|
|
|
1,202,551
|
|
Accumulated
other comprehensive loss
|
|
|
|
(284
|
)
|
|
(309
|
)
|
Retained
earnings
|
|
|
|
77,489
|
|
|
25,823
|
|
Total
common
stockholder's equity
|
|
|
|
1,380,497
|
|
|
1,333,877
|
|
Long-term
debt
and other long-term obligations
|
|
|
|
477,104
|
|
|
476,504
|
|
|
|
|
|
1,857,601
|
|
|
1,810,381
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
|
127,375
|
|
|
162,937
|
|
Accumulated
deferred income taxes
|
|
|
|
120,185
|
|
|
106,871
|
|
Retirement
benefits
|
|
|
|
107,860
|
|
|
102,046
|
|
Asset
retirement obligations
|
|
|
|
75,740
|
|
|
72,295
|
|
Other
|
|
|
|
53,165
|
|
|
54,275
|
|
|
|
|
|
484,325
|
|
|
498,424
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10) |
|
|
|
|
|
|
|
|
|
|
|
$
|
2,732,581
|
|
$
|
2,698,577
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Electric Company are an integral part of these balance
sheets.
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
56,666
|
|
$
|
24,852
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
36,269
|
|
|
37,721
|
|
Amortization
of regulatory assets
|
|
|
40,854
|
|
|
38,930
|
|
Deferral
of
new regulatory assets
|
|
|
(21,050
|
)
|
|
-
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(56,272
|
)
|
|
(41,301
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
14,518
|
|
|
(2,765
|
)
|
Accrued
retirement benefit obligations
|
|
|
1,808
|
|
|
3,005
|
|
Accrued
compensation, net
|
|
|
999
|
|
|
(1,695
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
22,719
|
|
|
97,130
|
|
Prepayments
and other current assets
|
|
|
(2,977
|
)
|
|
(8,620
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(15,555
|
)
|
|
(15,671
|
)
|
Accrued
taxes
|
|
|
(9,841
|
)
|
|
11,235
|
|
Accrued
interest
|
|
|
5,468
|
|
|
5,594
|
|
Other
|
|
|
(2,188
|
)
|
|
4,433
|
|
Net
cash
provided from operating activities
|
|
|
71,418
|
|
|
152,848
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
21,278
|
|
|
-
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
(11,534
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
(51,747
|
)
|
Dividend
Payments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(5,000
|
)
|
|
(32,000
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
16,278
|
|
|
(95,281
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(81,228
|
)
|
|
(61,680
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(2,976
|
)
|
|
5,724
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
66,781
|
|
|
59,820
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(66,781
|
)
|
|
(59,820
|
)
|
Other,
net
|
|
|
(3,480
|
)
|
|
(1,612
|
)
|
Net
cash used
for investing activities
|
|
|
(87,684
|
)
|
|
(57,568
|
)
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
12
|
|
|
(1
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
35
|
|
|
36
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
47
|
|
$
|
35
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Electric Company are an integral part of these
statements.
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Pennsylvania Electric Company:
We
have reviewed the
accompanying consolidated balance sheet of Pennsylvania Electric Company and
its
subsidiaries as of September 30, 2006, and the related consolidated statements
of income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2006 and 2005 and the consolidated statements of
cash flows for the nine-month periods ended September 30, 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.
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 9 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
October
31,
2006
|
PENNSYLVANIA
ELECTRIC COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS
OF
RESULTS
OF
OPERATIONS AND
FINANCIAL CONDITION
Penelec
is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts business
in
northern, western and south central Pennsylvania, providing regulated
transmission and distribution services. Penelec also provides generation
services to those customers electing to retain Penelec as their power supplier.
Results
of Operations
Net
income in the
third quarter of 2006 increased to $18 million, compared to a $2 million
net loss in the third quarter of 2005. The increase in net income resulted
from
the deferral of new regulatory assets, higher revenues and lower purchased
power
costs which were partially offset by higher general taxes and interest expense.
In the first nine months of 2006, net income increased to $57 million, compared
to $25 million in the first nine months of 2005. The increase in net income
resulted from the deferral of new regulatory assets, higher revenues and lower
other operating costs which were partially offset by higher purchased power
costs, general taxes and interest expense, as discussed below.
Revenues
Revenues
increased
by $13 million in the third quarter of 2006 and $14 million in the first nine
months of 2006, compared to the same periods of 2005. The increase in the third
quarter of 2006 was primarily due to higher retail generation revenues and
transmission revenues.
The increase in the
first nine months of 2006 was due primarily to higher retail generation revenues
partially offset by lower transmission and distribution revenues. Retail
generation revenues increased by $10 million in the third quarter of 2006 and
$33 million for the first nine months of 2006 primarily due to higher KWH sales
to industrial customers and higher composite unit prices in all customer
classes. Industrial sales increased $6 million for the third quarter of 2006
and
$21 million for the first nine months of 2006 primarily due to the return of
customers from alternative suppliers. Generation service provided by alternative
suppliers as a percent of total industrial sales in Penelec’s service area
decreased by 7.2 percentage points and 11.2 percentage points in the third
quarter and the first nine months of 2006, respectively, compared with the
corresponding periods of 2005.
Higher
composite
unit prices also increased generation revenues from residential customers by
$1 million and $4 million and from commercial customers by $3 million
and $8 million in the third quarter and first nine months of 2006, respectively.
Distribution
revenues were essentially unchanged in the third quarter of 2006 compared with
the same period of 2005. This occurred as a result of the increase from higher
composite unit prices substantially offset by a 1.1% decrease in KWH deliveries.
The decrease in KWH deliveries primarily resulted from the milder weather in
the
third quarter of 2006 (a 16.5% decrease in cooling degree days) compared to
the
same period in 2005. For the first nine months of 2006, distribution revenues
decreased $3 million due to a 1.6% decrease in KWH deliveries partially offset
by higher composite unit prices. Reduced KWH deliveries reflected milder weather
in the first nine months of 2006 (a 22.9% decrease in cooling degree days and
a
12.0% decrease in heating degree days) compared with the same period in
2005.
Transmission
revenues increased by $2 million in the third quarter of 2006 due to Penelec
exercising their right for additional auction revenue rights beginning in June
2006 compared to the same time period in 2005. For the first nine months of
2006, transmission revenues decreased $18 million due to lower transmission
load
requirements and lower prices. The decreased loads for the first nine months
of
2006 (and related lower congestion revenues) resulted from milder weather
conditions, as discussed above, and also resulted in decreased transmission
expenses discussed further below. For
the first nine
months of 2006, other revenues also increased by $1 million for a payment
received in the first quarter of 2006 under a contract provision associated
with
the prior sale of TMI Unit 1. Under the contract, additional payments are
received if subsequent energy prices rise above specified levels, which
occurred. This payment was credited to Penelec’s customers, resulting in no net
earnings effect.
Changes
in KWH sales
by customer class in the third quarter and first nine months of 2006 compared
to
the respective periods in 2005 are summarized in the following
table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
|
Residential
|
|
|
(2.5
|
)%
|
|
(2.2
|
)%
|
Commercial
|
|
|
(0.2
|
)%
|
|
(0.5
|
)%
|
Industrial
|
|
|
8.8
|
%
|
|
12.8
|
%
|
Total
Retail Electric Generation Sales
|
|
|
1.6
|
%
|
|
2.7
|
%
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
(2.7
|
)%
|
|
(2.4
|
)%
|
Commercial
|
|
|
(0.8
|
)%
|
|
(1.4
|
)%
|
Industrial
|
|
|
(0.1
|
)%
|
|
(1.2
|
)%
|
Total
Distribution Deliveries
|
|
|
(1.1
|
)%
|
|
(1.6
|
)%
|
|
|
|
|
|
|
|
|
Expenses
Total
expenses
decreased by $22 million or 7.7% in the third quarter of 2006 and $42 million
or
5.3% in the first nine months of 2006 compared with the same periods in 2005.
The following table presents changes from the prior year by expense category:
|
|
Three
|
|
Nine
|
|
Expenses
Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
(12
|
)
|
$
|
7
|
|
Other
operating costs
|
|
|
(1
|
)
|
|
(31
|
)
|
Provision
for
depreciation
|
|
|
(1
|
)
|
|
(2
|
)
|
Amortization
of regulatory assets
|
|
|
-
|
|
|
2
|
|
Deferral
of
new regulatory assets
|
|
|
(9
|
)
|
|
(21
|
)
|
General
taxes
|
|
|
1
|
|
|
3
|
|
Net
decrease in expenses
|
|
$
|
(22
|
)
|
$
|
(42
|
)
|
|
|
|
|
|
|
|
|
Purchased
power
costs decreased due to increased NUG cost deferrals of $11 million and a
slight decrease of $1 million in purchased power costs due to lower
composite unit prices, partially offset by increased volumes purchased to meet
higher customer load. The nine month increase in purchased power costs was
due
to increased purchases to meet higher customer load and higher composite unit
prices. This increase was partially offset by higher NUG cost deferrals of
$15 million for the first nine months of 2006.
Reduced
other
operating costs in the third quarter of 2006 compared to the same period in
2005
were due to lower transmission expenses resulting from lower congestion charges.
Partially offsetting these lower transmission were increased labor expenses
due
to higher levels of maintenance activities in the third quarter of 2006 for
energy delivery operations and reliability initiatives compared to higher levels
of construction activities in the third quarter of 2005. Other operating costs
decreased the first nine months of 2006 compared to the same period of 2005
due
primarily to lower transmission expenses resulting from lower congestion
charges. Expenses were further reduced due to higher levels of construction
activities in the first nine months of 2006 compared to a higher level of
maintenance activities for the same period of 2005. The deferral of new
regulatory assets in 2006 reflected the May 4, 2006 PPUC approval of Penelec’s
request to defer certain 2006 transmission-related costs (see Regulatory Matters
for further discussion). For
both periods,
general taxes increased primarily due to higher Pennsylvania gross receipt
taxes.
Capital
Resources and Liquidity
Penelec’s
cash
requirements for the remainder of 2006 for expenses, construction expenditures
and scheduled debt maturities, are expected to be met by a combination of cash
from operations and short-term credit arrangements.
Changes
in Cash
Position
As
of September 30,
2006, Penelec had $47,000 of cash and cash equivalents compared with $35,000
as
of December 31, 2005. The major sources of changes in these balances are
summarized below.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities in the first nine months of 2006 and 2005 were as follows:
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
74
|
|
$
|
59
|
|
Working
capital and other
|
|
|
(3
|
)
|
|
94
|
|
Net
cash
provided from operating activities
|
|
$
|
71
|
|
$
|
153
|
|
|
|
|
|
|
|
|
|
(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. Penelec believes that cash earnings is a useful financial measure because
it provides investors and management with an additional means of evaluating
its
cash-based operating performance. Generally, a non-GAAP financial measure is
a
numerical measure of a company’s historical or future financial performance,
financial position, or cash flows that either excludes or includes amounts,
or
is subject to adjustment that has the effect of excluding or including amounts,
that are not normally excluded or included in the most directly comparable
measure calculated and presented in accordance with GAAP. In addition, cash
earnings (non-GAAP) are not defined under GAAP. Management believes presenting
this non-GAAP measure provides useful information to investors in assessing
Penelec’s operating performance from a cash perspective without the effects of
material unusual economic events. Penelec’s management frequently references
these non-GAAP financial measures in its decision-making, using them to
facilitate historical and ongoing performance comparisons as well as comparisons
to the performance of peer companies. These non-GAAP measures should be
considered in addition to, and not as a substitute for, their most directly
comparable financial measures prepared in accordance with GAAP.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
57
|
|
$
|
25
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
36
|
|
|
38
|
|
Amortization
of regulatory assets
|
|
|
41
|
|
|
39
|
|
Deferral
of
new regulatory assets
|
|
|
(21
|
)
|
|
-
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(56
|
)
|
|
(41
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
14
|
|
|
(3
|
)
|
Other
non-cash
items
|
|
|
3
|
|
|
1
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
74
|
|
$
|
59
|
|
|
|
|
|
|
|
|
|
The
$15 million
increase in cash earnings is described above under “Results of Operations.” The
$97 million change from working capital primarily resulted from a decrease
of $74 million in cash provided from the collection of receivables and a
$21 million decrease in accrued taxes.
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities was $16 million in the first nine months of 2006
compared to net cash used for financing activities of $95 million in the
first nine months of 2005. The change reflects a $73 million increase in
short-term borrowings, a $27 million reduction in common stock dividend
payments to FirstEnergy and an $11 million decrease in long-term debt
redemptions.
Penelec
had
approximately $21 million of cash and temporary investments (which includes
short-term notes receivable from associated companies) and approximately $282
million of short-term indebtedness as of September 30, 2006. Penelec has
authorization from the FERC to incur short-term debt of up to $250 million
and
authorization from the PPUC to incur money pool borrowings of up to
$300 million. In addition, Penelec has $75 million of available
accounts receivable financing facilities as of September 30, 2006 through
Penelec Funding, Penelec's wholly owned subsidiary. As a separate legal entity
with separate creditors, Penelec Funding would have to satisfy its obligations
to creditors before any of its remaining assets could be made available to
Penelec. As of September 30, 2006 the facility was drawn for
$66 million. The annual facility fee is 0.125% on the entire finance
limit.
Penelec
will not
issue FMB other than as collateral for senior notes, since its senior note
indentures prohibit (subject to certain exceptions) Penelec from issuing any
debt which is senior to the senior notes. As of September 30, 2006, Penelec
had
the ability to issue $60 million of additional senior notes based upon FMB
collateral. Penelec has no restrictions on the issuance of preferred
stock.
On
August 24, 2006,
Penelec,
FirstEnergy, OE,
Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as Borrowers, entered into a new
$2.75 billion five-year revolving credit facility, which replaced the prior
$2 billion credit facility. FirstEnergy may request an increase in the total
commitments available under the new facility up to a maximum of $3.25 billion.
Commitments
under
the new facility are available until August 24, 2011, unless the lenders
agree, at the request of the Borrowers, to two additional one-year extensions.
Generally, borrowings under the facility must be repaid within 364 days.
Available amounts for each Borrower are subject to a specified sub-limit, as
well as applicable regulatory and other limitations. Penelec's
borrowing
limit under the facility is $250 million.
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
totaled $259 million.
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 September 30, 2006, Penelec’s debt to
total capitalization as defined under the revolving credit facility was
35%.
The
facility does
not contain any provisions that either restrict Penelec'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 Penelec's credit ratings.
Penelec has the ability to borrow from its regulated affiliates and FirstEnergy
to meet its short-term working capital requirements. FESC administers this
money
pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
Companies receiving a loan under the money pool agreements must repay the
principal, 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
nine months of 2006 was 5.09%.
Penelec’s
access to
capital markets and costs of financing are dependent on the ratings of its
securities and that of FirstEnergy. The ratings outlook from S&P on all
securities is stable. The ratings outlook from Moody's and Fitch on all
securities is positive.
Cash
Flows From
Investing Activities
In
the first nine
months of 2006, net cash used for investing activities totaled $88 million
compared to $58 million in the first nine months of 2005. The increase primarily
resulted from a $20 million increase in property additions and a $9 million
increase in loans to associated companies. Expenditures for property additions
primarily support Penelec’s energy delivery operations and reliability
initiatives.
During
the last
quarter of 2006, capital requirements for property additions are expected to
be
approximately $24 million. This cash requirement is expected to be
satisfied from a combination of internal cash and short-term credit
arrangements.
Penelec’s
capital
spending for the period 2006-2010 is expected to be approximately
$494 million, of which approximately $108 million applies to 2006. The
capital spending is primarily for property additions supporting the distribution
of electricity.
Market
Risk Information
Penelec
uses various
market risk sensitive instruments, including derivative contracts, primarily
to
manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee,
comprised of members of senior management, provides general oversight to risk
management activities.
Commodity
Price
Risk
Penelec
is exposed
to market risk primarily due to fluctuations in electricity, energy
transmission, natural gas, coal, and emission prices. To manage the volatility
relating to these exposures, Penelec 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. All
derivatives that fall within the scope of SFAS 133 must be recorded at
their fair value and marked to market. The majority of Penelec’s derivative
hedging contracts qualify for the normal purchase and normal sale exception
under SFAS 133. Contracts that are not exempt from such treatment include
the power purchase agreements with NUG entities that were structured pursuant
to
the Public Utility Regulatory Policies Act of 1978. These
non-trading
contracts had been adjusted to fair value at the end of each quarter, with
a
corresponding regulatory asset recognized for above-market costs. On April
1,
2006, Penelec elected to apply the normal purchase and normal sale exception
to
certain NUG power purchase agreements having a fair value of $14 million
(included in “Other” in the table below) in accordance with guidance in DIG C20.
The change in the fair value of commodity derivative contracts related to energy
production during the third quarter and first nine months of 2006 is summarized
in the following table:
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
September
30, 2006
|
|
September
30, 2006
|
|
of
Commodity Derivative Contracts
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
(In
millions)
|
|
Change
in the Fair Value of
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net asset at beginning of period
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
$
|
27
|
|
$
|
-
|
|
$
|
27
|
|
New
contract
value when entered
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
|
Change
in
techniques/assumptions
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
|
-
|
|
|
(3
|
)
|
Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(14
|
)
|
|
-
|
|
|
(14
|
)
|
Net
Assets - Derivative Contracts
at
End
of Period (1)
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(4
|
)
|
$
|
-
|
|
$
|
(4
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OCI
(pre-tax)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Regulatory
liability
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3
|
|
$
|
-
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes
$11 million
in a non-hedge commodity derivative contract which is offset by a regulatory
liability.
(2) 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
September 30, 2006 as follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
Other
noncurrent liabilities
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
assets
|
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
The
valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, Penelec relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. Penelec uses these results to develop estimates of fair value
for financial reporting purposes and for internal management decision making.
Sources of information for the valuation of commodity derivative contracts
as of
September 30, 2006 are summarized by year in the following table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
2006(1)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
external
sources (2)
(3)
|
|
$
|
3
|
|
$
|
3
|
|
$
|
2
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
10
|
|
Prices
based
on models(3)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
3
|
|
$
|
3
|
|
$
|
2
|
|
$
|
2
|
|
$
|
2
|
|
$
|
-
|
|
$
|
12
|
|
(1) For
the last quarter
of 2006.
(2) Broker
quote
sheets.
(3) Includes
$11 million
from a non-hedge commodity derivative contract that is offset by a regulatory
liability and does not affect earnings.
Penelec
performs
sensitivity
analyses to estimate its exposure to the market risk of its commodity positions.
A hypothetical 10% adverse shift in quoted market prices in the near term on
both of Penelec's trading and non-trading derivative instruments would not
have
had a material effect on its consolidated financial position or cash flows
as of
September 30, 2006. Penelec estimates that if energy commodity prices
experienced an adverse 10% change, net income for the next twelve months would
not change, as the prices for all commodity positions are already above the
contract price caps.
Equity
Price
Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their current
fair value of approximately $68 million and $62 million as of
September 30, 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 September 30, 2006.
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.
Penelec’s net regulatory liabilities were approximately $127 million and
$163 million as of September 30, 2006 and December 31, 2005,
respectively, and are included under Noncurrent Liabilities on the Consolidated
Balance Sheets.
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 and the companies filed initial testimony on
March 1, 2006. On May 4, 2006, the PPUC consolidated this proceeding
with the April 10, 2006 comprehensive rate filing proceeding discussed
below. Met-Ed and Penelec are unable to predict the outcome of this
matter.
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 were held on June 8, 2006. On July 19, 2006, the
Commonwealth Court issued its decision affirming the PPUC’s prior orders.
Although the decision denied the appeal of Met-Ed and Penelec, they had
previously accounted for the treatment of costs required by the PPUC’s October
2003 orders.
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 an agent for Met-Ed or Penelec in procuring the
services under 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 Penelec procures 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 its PLR obligations for
2008, 2009 and 2010, respectively, for which Committed Resources have not been
obtained from the market. On September 26, 2006, Penelec successfully
conducted a competitive RFP for 33% of its PLR obligation for which Committed
Resources had not been obtained for the period December 1, 2006 through
December 31, 2008.
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, further reduce, 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.
Penelec
made a
comprehensive rate filing with the PPUC on April 10, 2006 that addresses a
number of transmission, distribution and supply issues. If Penelec's preferred
approach involving accounting deferrals is approved, the filing would increase
annual revenues by $157 million. That filing includes, among other things,
a request to charge customers for an increasing amount of market priced power
procured through a CBP 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. 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, 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 are also included in the filing. The filing
contemplates an increase in distribution rates for Penelec of $20 million
annually. The PPUC suspended the effective date (June 10, 2006) of these
rate changes for seven months after the filing as permitted under Pennsylvania
law. If the PPUC adopts the overall positions taken in the intervenors’
testimony as filed, this would have a material adverse effect on the financial
statements of FirstEnergy and Penelec. Hearings were held in late August 2006
and all reply briefs were filed by October 6, 2006. The ALJ’s recommended
decision is due by November 8, 2006 and the PPUC decision is expected by January
12, 2007.
The
annual goodwill
impairment analysis performed in the third quarter of 2006 assumed management's
best estimate of the rate increases that are expected to be granted in January
2007 under Penelec’s comprehensive rate filing. If the PPUC authorizes less than
the amounts assumed, an additional impairment analysis would be performed at
that time and this could result in a future goodwill impairment loss that could
be material. If rate relief were completely denied, it is estimated that
approximately $374 million of Penelec’s goodwill would be impaired and
written off. However, no adjustment to FirstEnergy’s goodwill on a consolidated
basis would be recognized in that circumstance because the fair value of its
regulated segment (which represents FirstEnergy's reporting unit to evaluate
goodwill) would continue to exceed the carrying value of its investment in
the
segment.
As of September 30, 2006, Penelec's regulatory deferrals pursuant to the
1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
FirstEnergy/GPU Merger Settlement Stipulation was $56 million. Penelec's
$56 million is subject to the pending resolution of taxable income issues
associated with NUG trust fund proceeds. The PPUC recently conducted a review
and audit of a modification to the NUG purchased power stranded cost accounting
methodology for Penelec. On August 18, 2006, a PPUC Order was entered requiring
Penelec to reflect the deferred NUG cost balances as if the stranded cost
accounting methodology modification had not been implemented. Penelec continues
to believe that the stranded cost accounting methodology modification is
appropriate and filed a petition with the PPUC pursuant to its Order for
authorization to reflect the stranded cost accounting methodology modification
effective January 1, 1999.
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 all intervened in the case. 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 above. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Penelec deferred approximately
$21 million, representing transmission costs that were incurred from
January 1, 2006 through September 30, 2006. On June 5, 2006, the OCA filed
before the Commonwealth Court a petition for review of the PPUC’s approval of
the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion
to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be
determined in the comprehensive rate filing proceeding
discussed above.
On
November 18,
2004, the FERC issued an order eliminating the RTOR for transmission service
between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
transmission owners within MISO and PJM to submit compliance filings containing
a SECA mechanism 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 was held in May 2006. Initial briefs were submitted
on
June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding Judge
issued an Initial Decision on August 10, 2006, rejecting the compliance filings
made by the RTOs and transmission owners, ruling on various issues and directing
new compliance filings. This decision is subject to review and approval by
the
FERC. Briefs addressing the Initial Decision were filed on September 11, 2006
and October 20, 2006. A final order could be issued by the FERC by the end
of
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 refund 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. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
the cost of all PJM transmission facilities should be recovered through a
postage stamp rate. The
ALJ recommended
an April 1, 2006 effective date for this change in rate design. If the FERC
accepts this recommendation, the transmission rate applicable to many load
zones
in PJM would increase. FirstEnergy believes that significant additional
transmission revenues would have to be recovered from the JCP&L, Met-Ed and
Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
on August 14, 2006 and September 5, 2006. The case will be reviewed by the
FERC
with a decision anticipated in the fourth quarter of 2006.
See
Note 11 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania, including a more detailed discussion
of
reliability initiatives, including actions by the PPUC that impact
Penelec.
Environmental
Matters
Penelec
accrues
environmental liabilities when it concludes that it is probable that it has
an
obligation for such costs and can reasonably determine the amount of such costs.
Unasserted claims are reflected in Penelec's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
Penelec
has been
named a PRP at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site 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 September
30, 2006, based on estimates of the total costs of cleanup, Penelec’s
proportionate responsibility for such costs and the financial ability of other
unaffiliated entities to pay.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to Penelec’s normal business operations pending against Penelec. The
other material items not otherwise discussed below are described in
Note 10(C) to the consolidated financial statements.
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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the
EPACT
that could require additional material expenditures.
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, results of operations and cash
flows.
New
Accounting Standards and Interpretations
|
SAB
108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial
Statements”
|
In September 2006, the SEC issued SAB 108, which provides interpretive guidance
on how registrants should quantify financial statement misstatements. There
is
currently diversity in practice, with the two commonly used methods to quantify
misstatements being the “rollover” method (which primarily focuses on the income
statement impact of misstatements) and the “iron curtain” method (which focuses
on the balance sheet impact). SAB 108 requires registrants to use a dual
approach whereby both of these methods are considered in evaluating the
materiality of financial statement errors. Prior materiality assessments will
need to be reconsidered using both the rollover and iron curtain methods. This
guidance will be effective for Penelec in the fourth quarter of 2006. Penelec
does
not expect this Statement to have a material impact on its financial
statements.
SFAS
157 - “Fair
Value Measurements”
In September 2006, the FASB issued SFAS 157, that establishes how companies
should measure fair value when they are required to use a fair value measure
for
recognition or disclosure purposes under GAAP. This Statement addresses the
need
for increased consistency and comparability in fair value measurements and
for
expanded disclosures about fair value measurements. The key changes to current
practice are: (1) the definition of fair value which focuses on an exit price
rather than entry price; (2) the methods used to measure fair value such as
emphasis that fair value is a market-based measurement, not an entity-specific
measurement, as well as the inclusion of an adjustment for risk, restrictions
and credit standing; and (3) the expanded disclosures about fair value
measurements.
This Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
Penelec is currently evaluating the impact of this Statement on its financial
statements.
|
SFAS
158 -
“Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88,
106, and
132(R)”
|
In September 2006, the FASB issued SFAS 158, which requires companies to
recognize a net liability or asset to report the overfunded or underfunded
status of their defined benefit pension and other postretirement benefit plans
on their balance sheets and recognize changes in funded status in the year
in
which the changes occur through other comprehensive income. The funded status
to
be measured is the difference between plan assets at fair value and the benefit
obligation. This Statement requires that gains and losses and prior service
costs or credits, net of tax, that arise during the period be recognized as
a
component of other comprehensive income and not as components of net periodic
benefit cost. Additional information should also be disclosed in the notes
to
the financial statements about certain effects on net periodic benefit cost
for
the next fiscal year that arise from delayed recognition of the gains or losses,
prior service costs or credits, and transition asset or obligation. Upon the
initial application of this Statement and subsequently, an employer should
continue to apply the provisions in Statements 87, 88 and 106 in measuring
plan
assets and benefit obligations as of the date of its statement of financial
position and in determining the amount of net periodic benefit cost. This
Statement is effective for Penelec as of December 31, 2006. Penelec
is
currently evaluating the impact of this Statement on its financial
statements.
FSP
FIN 46(R)-6
- “Determining the Variability to Be Considered in Applying FASB interpretation
No. 46(R)”
In
April 2006, the
FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
determine the variability to be considered in applying FASB interpretation
No.
46 (revised December 2003). Penelec adopted FIN 46(R) in the first quarter
of
2004, consolidating VIE’s when Penelec or one of its subsidiaries is determined
to be the VIE’s primary beneficiary. The variability that is considered in
applying interpretation 46(R) affects the determination of (a) whether the
entity is a VIE; (b) which interests are variable interests in the entity;
and
(c) which party, if any, is the primary beneficiary of the VIE. This FSP states
that the variability to be considered shall be based on an analysis of the
design of the entity, involving two steps:
Step
1:
|
Analyze
the
nature of the risks in the entity
|
Step
2:
|
Determine
the
purpose(s) for which the entity was created and determine the variability
the entity is designed to create and pass along to its interest
holders.
|
After
determining
the variability to consider, the reporting enterprise can determine which
interests are designed to absorb that variability. The guidance in this FSP
is
applied prospectively to all entities (including newly created entities) with
which that enterprise first becomes involved and to all entities previously
required to be analyzed under interpretation 46(R) when a reconsideration event
has occurred after July 1, 2006. Penelec does not expect this Statement to
have a material impact on its financial statements.
FIN
48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109.”
In
June 2006, the
FASB issued FIN 48 which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken
on a
tax return. This interpretation also provides guidance on derecognition,
classification, interest, penalties, accounting in interim periods, disclosure
and transition. The evaluation of a tax position in accordance with this
interpretation will be a two-step process. The first step will determine if
it
is more likely than not that a tax position will be sustained upon examination
and should therefore be recognized. The second step will measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of benefit to recognize in the financial statements. This interpretation
is effective for fiscal years beginning after December 15, 2006. Penelec is
currently evaluating the impact of this Statement.
ITEM
3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
See
“Management’s
Discussion and Analysis of Results of Operation and Financial Condition -
Market
Risk Information” in Item 2 above.
ITEM
4.
CONTROLS AND PROCEDURES
(a) EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
The
applicable
registrant's chief executive officer and chief financial officer have reviewed
and evaluated the registrant's disclosure controls and procedures. 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 on that evaluation, those officers have concluded
that the applicable registrant's disclosure controls and procedures are
effective and were designed to bring to their attention material information
relating to the registrant and its consolidated subsidiaries by others within
those entities.
(b) CHANGES
IN
INTERNAL CONTROLS
During
the quarter
ended September 30, 2006, the
registrants
modified the internal controls over the preparation and review of their
Consolidated Statements of Cash Flows. There
were no other
changes in the registrants' internal control over financial reporting that
have
materially affected, or are reasonably likely to materially affect, the
registrants' internal control over financial reporting.
PART
II. OTHER INFORMATION
ITEM
1. LEGAL
PROCEEDINGS
Information
required
for Part II, Item 1 is incorporated by reference to the discussions in Notes
10
and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form
10-Q.
ITEM
1A. RISK
FACTORS
See
Item 1A RISK
FACTORS in Part I of the Form 10-K for the year ended December 31, 2005 for
a discussion of the risk factors of FirstEnergy and the subsidiary registrants.
For the quarter ended September 30, 2006, there have been no material
changes to these risk factors.
ITEM
2. UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The
table below
includes information on a monthly basis regarding purchases made by FirstEnergy
of its common stock.
|
|
Period
|
|
|
|
July
1-31,
|
|
August
1-31,
|
|
September
1-30,
|
|
Third
|
|
|
|
2006
|
|
2006
|
|
2006
|
|
Quarter
|
|
Total
Number
of Shares Purchased (a)
|
|
203,030
|
|
10,872,244
|
|
265,207
|
|
11,340,481
|
|
Average
Price
Paid per Share
|
|
$55.33
|
|
$56.44
|
|
$56.42
|
|
$56.42
|
|
Total
Number
of Shares Purchased
|
|
|
|
|
|
|
|
|
|
As
Part of
Publicly Announced Plans
|
|
|
|
|
|
|
|
|
|
or
Programs
(b)
|
|
--
|
|
10,630,759
|
|
--
|
|
10,630,759
|
|
Maximum
Number
(or Approximate Dollar
|
|
|
|
|
|
|
|
|
|
Value)
of
Shares that May Yet Be
|
|
|
|
|
|
|
|
|
|
Purchased
Under the Plans or Programs
|
|
12,000,000
|
|
1,369,241
|
|
1,369,241
|
|
1,369,241
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Share
amounts
reflect purchases on the open market to satisfy FirstEnergy's obligations
to deliver common stock under its Executive and Director Incentive
Compensation Plan, Deferred Compensation Plan for Outside Directors,
Executive Deferred Compensation Plan, Savings Plan and Stock Investment
Plan. In addition, such amounts reflect shares tendered by employees
to
pay the exercise price or withholding taxes upon exercise of stock
options
granted under the Executive and Director Incentive Compensation Plan
and
shares purchased as part of publicly announced plans.
|
|
|
(b)
|
FirstEnergy
publicly announced, on June 20, 2006, a plan to repurchase up to
12 million shares of its common
stock.
|
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
FirstEnergy
|
|
|
10.1
*
|
Confirmation
dated August 9, 2006 between FirstEnergy Corp and JP Morgan Chase
Bank
National Association
|
|
10.2
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
OE
|
|
|
10.1
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
Penn
|
|
|
10.1
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
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.
|
|
|
CEI
|
|
|
10.1
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
TE
|
|
|
10.1
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
JCP&L
|
|
|
4.1
|
Indenture
dated as of August 10, 2006 between JCP&L Transition Funding II LLC as
Issuer and The Bank of New York as Trustee (incorporated by reference
to
Exhibit 4.1 of JCP&L's Form 8-K filed on August 10,
2006)
|
|
4.2
|
2006-A
Series
Supplement dated as of August 10, 2006 between JCP&L Transition
Funding II LLC as Issuer and The Bank of New York as Trustee (incorporated
by reference to Exhibit 4.2 of JCP&L's Form 8-K filed on August 10,
2006)
|
|
4.3
|
Form
of
Transition Bond (incorporated by reference to Exhibit 4.2 of JCP&L's
Form 8-K filed on August 10, 2006)
|
|
10.1
|
Bondable
Transition Property Sale Agreement dated as of August 10, 2006 between
JCP&L Transition Funding II LLC as Issuer and Jersey Central Power
& Light Company as Seller (incorporated by reference to Exhibit 10.1
of JCP&L's Form 8-K filed on August 10, 2006)
|
|
10.2
|
Bondable
Transition Property Service Agreement dated as of August 10, 2006
between
JCP&L Transition Funding II LLC as Issuer and Jersey Central Power
& Light Company as Servicer (incorporated by reference to Exhibit 10.2
of JCP&L's Form 8-K filed on August 10, 2006)
|
|
10.3
|
Administration
Agreement dated as of August 10, 2006 between JCP&L Transition Funding
II LLC as Issuer and FirstEnergy Service Company as Administrator
(incorporated by reference to Exhibit 10.3 of JCP&L's Form 8-K filed
on August 10, 2006)
|
|
10.4
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief executive 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.
|
|
|
Met-Ed
|
|
|
10.1
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
Penelec
|
|
|
10.1
|
$2,750,000,000
Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
Ohio
Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power
& Light Company, Metropolitan Edison Company and Pennsylvania Electric
Company, as Borrowers, the banks party thereto, the fronting banks
party
thereto and the swing line lenders party thereto (incorporated by
reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
2006)
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
*
Confidential
treatment has been requested for certain portions of the Exhibit. Omitted
portions have been filed separately with the SEC.
Pursuant to reporting requirements of respective financings, FirstEnergy, OE,
CEI, TE, JCP&L, Met-Ed and Penelec 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 respective fixed charge ratios.
Pursuant
to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
OE,
CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this
Form 10-Q any instrument with respect to long-term debt if the respective
total amount of securities authorized thereunder does not exceed 10% of its
consolidated total assets, but each hereby agrees to furnish to the SEC 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
|
|
|
|
THE
CLEVELAND ELECTRIC
|
|
ILLUMINATING
COMPANY
|
|
Registrant
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
POWER COMPANY
|
|
Registrant
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
Registrant
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
Registrant
|
|
/s/Harvey
L.
Wagner
|
|
Harvey
L.
Wagner
|
|
Vice
President, Controller
|
|
and
Chief
Accounting Officer
|